Peters & Co. Energy Conference September 11, 2013

Transcription

1 Peters & Co. Energy Conference September 11, 2013

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," "2012 through 2015" 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; the top five strategic priorities for 2013.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 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 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 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 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 effects on our business and operations and on the forward-looking statements contained herein. 1 1

3 Market Profile TSX:PMT Common shares outstanding million Management ownership 25.4% Share price (5 day weighted average) $ 1.05 Market capitalization $ 156 million Total Net Debt $ 375 million Net bank debt $ 65 million Convertible debentures (PMT.DB.D; PMT.DB.E) $ 160 million Senior unsecured notes $ 150 million Enterprise value $ 531 million 30 day weighted average daily trading volume ~ 91,200 shares/day Enterprise Value $530 million 2

4 Perpetual Energy TSX:PMT Conventional Shallow Gas Distributing Trust DIVERSIFIED RESOURCE STYLE GROWTH ORIENTED ENTREPRENEURIAL EXPLORER, PRODUCER & MARKETER BUILT TO GROW BUILT TO PROSPER BUILT TO LAST 3

5 Operating Profile Eastern Alberta Conventional Shallow Gas Mannville Heavy Oil Bitumen Panny, Marten Hills, Liege Warwick Gas Storage Viking/Colorado Shallow Shale Gas Deep Basin Edson Wilrich Multi-Zone Liquids-Rich Gas Tight Oil and Gas Exploration Actual & Deemed Production (August 2013) Natural Gas NGL s and Oil Gas over Bitumen Deemed Production (1) P+P Reserves (3) Reserve to Production Ratio (P+P) (RLI) (3) Contingent Resource Bitumen (2) Warwick Gas Storage Working Gas Capacity (gross) (4) 22,900 Boe/d 87 MMcf/d 4,240 bbl/d 25 MMcf/d 372 Bcfe 9.1 Years 279 MMbbl 21.5 Bcf (1) Cash Flow = 0.5 x [(deemed production volume x 0.80) x (Alberta Reference Price - $0.3791/GJ)] (2) Best estimate as evaluated by McDaniel (3) As evaluated by McDaniel at year end 2012, adjusted for Elmworth sale (4) 30% ownership interest 4

6 Diversified Portfolio Built to Prosper SHALLOW GAS LIQUIDS- RICH GAS HEAVY OIL BITUMEN OTHER Maximize Cash Flow Invest For Growth Invest For Growth Advance and Optimize For Value Advance and Optimize For Value Eastern Alberta Conventional Viking/Colorado Shallow Shale Gas Edson Wilrich HZ Greater Edson Multi-zone Deep Basin Exploration Mannville Primary Mannville EOR Heavy Oil Exploration Panny Bluesky Marten Hills Clearwater Liege Grosmont and Leduc Other Warwick Gas Storage (30%) GOB Technical Solutions TriOil Shares Other Exploration Spectrum of Opportunities to Invest In Through Variable Commodity Cycles 5

7 Portfolio Management Strategy CASH FLOW GENERATORS Maximize Cash Flow Conventional Shallow Gas Warwick Gas Storage PROVEN DIVERSIFYING GROWTH STRATEGIES Invest For Growth Eastern Alberta Heavy Oil Edson Liquids-Rich Wilrich + Gas + MEDIUM AND LONG TERM VALUE STRATEGIES Optimize and Advance Viking/Colorado Shale Gas Bitumen Panny Bluesky Marten Hills Clearwater Liege Carbonates Other GOB Technical Solutions Tight Oil & Gas Exploration Entrepreneurial Approach to Value Creation 6

8 Asset Base Transformation 100% 4,500 25% Production (% of total) 90% 80% 70% 60% 50% 40% 30% 20% Resource-style oil & liquids growth assets now 40% of production >4,000 bbl/d oil & NGL s (>20%) 30% of gas from Deep Basin Oil and NGL Production (bbl/d) 4,000 3,500 3,000 2,500 2,000 1,500 1,000 20% 15% 10% 5% Percentage of total production (%) 10% 500 0% E E 0% Shallow Gas Production Deep Basin Gas Production NGL Production Oil Production NGL Oil % Oil and NGL of Total Production Eight Fold Increase in Production from Resource-Style Growth Assets 7

9 Cash Flow Diversification Production Revenue from Oil and NGL 70% 60% 2013 Forecast Revenue (1) % 40% 30% 20% 10% Oil Gas NGL Hedging Gas Storage 0 0% Q110 Q210 Q310 Q410 Q111 Q211 Q311 Q411 Q112 Q212 Revenue ($MM) Q312 Q412 Q113 Q213 Q313E Q413E Oil and NGL Revenue Oil and NGL % of Total Revenue (1) Assumes forward commodity prices as of August 27, 2013 Oil and NGL Grown to Contribute Close to 50% of Revenue 8

10 2013 Top 5 Strategic Priorities 1. Maximize Value of Mannville Heavy Oil 2. Position for Growth of Edson Liquids-Rich Gas 3. Advance and Broaden Portfolio of High Impact Opportunities with Risk-Managed Investment 4. Manage Downside Risk and Reduce Debt 5. Prepare to Maximize Value from Shallow Gas in Gas Price Recovery Positive Momentum on All Fronts 9

11 Maximize Value of Mannville Heavy Oil

12 Eastern Alberta - Conventional Heavy Oil Mannville Discovered 12 Mannville pools 6 Lloyd, 5 Sparky, 1 Basal Quartz > 200 MMbbl Original Oil in Place > 10 5% recovery factor Current Production ~ 3,500 bbl/d (1) Low cost HZ development HZ $ 1.1 MM single lateral well $1.4 MM for multi-lateral well Average initial rate ~80 bbl/d Extensive in-house 3D & 2D seismic 123,000 net acres of lands 2013 H1 Activity 29 gross (27.7 net) wells Evaluating downspacing and multi-laterals 1 new pool evaluated outside Mannville 2013 H2 Activity Up to 14 gross (13.7 net) wells Planning for 2014 EOR execution (1) August D coverage Q Drilling Q Planned Drilling 150 Net Drilling Location in Inventory at Various Levels of Drill Readiness 11

13 Upper Mannville A Pool - Lloyd Channel Wells Performing At or OOIP = 30 MMbbls Cumulative to date 740 Mbbl ( ~ 2.4% recovery) Booked Reserves (year end 2012) 1.13 MMbbl (5% RF) 3 wells drilled in Q1 2013, 1 well Q2; 2 wells Q3 9 additional locations in inventory based on 100 m spacing Evaluating 50m infills Lloyd Channel, Upper Mannville A HZ Wells Production vs. Oil Cumulative 02/ W4/0 03/ W4/0 00/ W4/0 (On Production 1996) 00/ W4/0 02/ W4/0 00/ W4/0 LLOYD CHANNEL TYPE LOG 100/ W4/00 Oil Rates, bbl/d / W4/0 04/ W4/0 02/ W4/0 00/ W4/0 00/ W4/ / W4/ / W4/ Type Well Oil Cumulative, bbl Downspacing to 50m Infills in A Pool Could Add Up to 20 Low Risk Laterals 12

14 Mannville Heavy Oil Value Potential Capital (D,C & T) 10 % Projected Economics per Drilling Location $1.1 MM $1.05 MM ROR 105% 2013 Pricing Operating Costs Assumptions (from McDaniel) $92.50/bbl WTI; $26.90/bbl differential = $65.60 Hardisty heavy price $10.56 /Boe (first year) & $23.00 /Boe (lifetime) F&D $16.00 / Boe Type Curve IP 70 bbl/d, 1 year exit rate 44 bbl/d Capital Efficiency ~$20,150 Boe/d 2P Reserves 70 Mbbl per well Recycle Ratio 3.3 Royalties 5% for first 18 months Oil over shakers while drilling Sparky development pad HZ pad site Highly Profitable at Current Oil Prices 13

15 Upper Mannville I2I Sparky - Enhanced Recovery OOIP = 31 MMbbl (initial EOR area only); Total Pool: 53 MMbbl Cumulative to date 467 Mbbl Recovery Factor to date <1 %; Expect 5-8% on Primary Q drilled 4-100m infills, 16 additional locations in inventory Preparing for implementation of Water/Polymer flood in late Upper Mannville I2I HZ Wells Production vs. Type Well 00/ W4/0 00/ W4/0 00/ W4/0 00/ W4 02/ W Drills 2014 Drills Inventory / W4 02/ W4 00/ W4/0 SPARKY MID TYPE LOG 100/ W4/00 > 24 % DENSITY POROSITY 6 m OIL PAY Mid Sand Oil Rates, bbl/d / W4/0 02/ W4/0 03/ W4/0 00/ W4/0 00/ W4/0 02/ W4/0 00/ W4/ / W4/0 03/ W4/0 Type Well Oil Cumulative, bbl EOR Scheme Projected to Increase Recovery to 10-15% 14

16 Enhanced Oil Recovery Scope Pool (4) OOIP (1) Cumulative production to 12/31/12 P+P Reserves booked at 12/31/12 Implied Recovery Factor Expected Primary Recovery (5-8%) Potential with Secondary Recovery and EOR (10-15%) (MMbbl) (MMbbl) (MMbbl) (%) (MMbbl) (MMbbl) Sparky I2I (2) (3) 4.1% (3) Upper Mannville A (2) % Upper Mannville B (2) % Sparky O % Total % (1) Internal estimate (2) Portion of entire pool (3) Net reserves at 66.7% WI, recovery factor adjusted to gross (4) Select pools only highlighted Significant Scope for Increased Reserves & Value With Infill Drilling and Water / Polymer Floods 15

17 Position for Growth of Edson Liquids-Rich Gas

18 Edson Wilrich Liquids Rich Gas Sales Pipeline to Alliance Constructed Q2/Q Pipeline To Edson Deep Cut Plant 36 bbl/mmcf NGLs Gas Plant Capacity 30 MMcf/d 2014 Expand to 45+ MMcf/d Compressor Capacity 30 MMcf/d Edson Type Curve IP 4 MMcf/d Reserves 2.5 Bcfe/well West Edson Type Curve IP 12 MMcf/d Reserves 3.8 Bcfe/well Vertical Well Pre-2012 Horizontal Well 2012 Horizontal Well 2013 Location 2014 Potential Q1 Location Inventory of >100 Wilrich Horizontal Locations and Growing

19 West Edson Production 20 Ansell Net Raw Gas Production Compression Gas Plant and Capacity Sales Pipeline Increased from Construction 10 to 30 MMcf/d Onstream gross (50% WI) September 2013 Production Start Up from Single Rig Drill to Fill Program Which Commenced in August Gas Rate (MMcf/d) Dec-11 Feb-12 Apr-12 Jun-12 Aug-12 Oct-12 Dec-12 Feb-13 Apr-13 Jun-13 Aug-13 Oct-13 Dec-13 Date Gas Plant and Sales Pipeline Construction on Track.Tie-In to Alliance in Q Q3/Q4 Drilling Program to Maintain Plant at Capacity of 15 MMcf/d Net 18

20 Wilrich Value Potential - West Edson / /15 35 Capital (D,C & T) Projected Economics per Drilling Location $6.3 MM gross IP MMcf/d restricted rates 00/ / / % ROR F&D $4.93 MM BT 200% BT $9.92 / boe Daily Gas (MMcf/d) /14 07 McDaniels West Edson Type Curve Capital Efficiency Recycle Ratio 2.95 < $12,840 boe/d Assumptions (McDaniel) 2013 Pricing $3.18 / GJ; $57 / bbl NGL 6 Operating Costs $4.75 / boe (first year) Days on Production Well Depth Type Curve 2P Reserves Royalties Risk Inventory of 37 Net Locations at 2 Wells per Section Type Curve to be Reassessed at Year End 4,200 M HZ; 2,700 TVD IP 12.0 MMcf/d 1 year exit rate 1.5 MMcf/d 32 bbl/mmcf NGL/condensate 3.8 Bcfe per well 5% royalty until NGDDP credit of ~$2.7 MM is recovered Unrisked 19

21 Wilrich Value Potential - Edson 12 00/ /03 09 Projected Economics per Drilling Location 10 00/ /05 16 Capital (D,C & T) 10 % $4.9 MM $1.95 MM 00/05 36 ROR 40% BT 8 00/10 05 F&D $12.00 / boe Daily Gas (MMcfd) 6 4 IP 7 MMcf/d 00/ / / / /14 28 Capital Efficiency <$13,138 boe/d (first twelve months) Recycle Ratio 2.04 Assumptions (McDaniel) 2013 Pricing $3.18 / GJ; $61.00 / bbl NGL 00/15 36 Operating Costs $5.50 / boe (first year) 02/01 04 Well Depth 4,000 M HZ; 2,400 TVD 2 McDaniels Edson Type Curve Type Curve IP 4 MMcf/d 1 year exit rate 1.2 MMcf/d 33.5 bbl/mmcf NGL/condensate Days on Production 2P Reserves Royalties Risk 2.5 Bcfe per well 5% royalty until NGDDP credit of ~$2 MM is recovered Unrisked Inventory of 71 Net Locations at 2 Wells per Section Modeling Work Supports Possible Doubling of Inventory through Downspacing 20

22 2013 Full Year Capital Spending Plan Total Capital: $79 - $85 million H Wells Capital Remainder 2013 Wells Capital Total 2013 Wells Capital Mannville Heavy Oil 29 gross (27.7 net) $33.5 MM 3-12 gross ( net) Up to $17.7 MM Up to 41 (39.4 net) Up to $51.2 MM West Central Deep Basin (Wilrich) (1,2) $13.9 MM 4-6 gross (2-3 net) Up to $23.5 MM Up to 6 (3.0 net) Up to $37.4 MM Land, Seismic, ARO & Other $2.6 MM $5.0 MM $7.6 MM Total $50 MM Up to $46.2 MM $75 - $85 MM 1) Includes Q1 West Edson 3 well tie-in, trunk line and compressor station expansion and South Edson Extension completion and tie-in 2) Q2/Q3 capital includes refrigeration plant and sales pipeline Flexibility to Allocate Capital to Edson Wilrich or Mannville Heavy Oil Depending on Commodity Prices and Results 21

23 Optimize and Advance Medium to Long Term Opportunities Elmworth Montney - SOLD Viking/Colorado Shallow Shale Gas Bitumen

24 Viking / Colorado Shallow Shale Gas Belly River Play Fairway Cardium/ Colorado Wells Perpetual Lands Viking Proved Undeveloped Viking Probable Undeveloped Viking Proven Non-Producing Prospect Inventory 5 Yr Total Resource in Place > 130 Tcf Viking Booked Reserves 61 Bcf P+P primarily undeveloped 445 Vertical drills in FDC Average 138 MMcf / vertical well gross Unbooked Additional Rec. Resource 50+ Bcf lost due to price revisions Should be regained in gas price recovery Colorado Resource Potential Average 435 MMcf / well gross Expected HZ development at 8 wells/section 1.6 Tcf Potential Recoverable Resource Over 475 sections of land with unbooked Viking potential Over 1,300 net sections of lands with Colorado potential Extensive plant and pipeline infrastructure Develop Viking tight sand and Colorado Group shale together to reduce costs, increase recovery and enhance economics 23

25 Colorado Group Technical Advancement Colorado Group Free Gas in Place OGIP estimated to average 16 Bcf/section Proven recovery from Cardium equivalent zone through horizontal development Potential in up to 6 zones within 290m shale group Advanced detailed (3G) technical study Gas in Place, brittleness mapping, production inflow and fracture modeling Pilot work evaluated fracture performance through recompletions Monitor industry horizontal development pilots Pilot planning and execution Recompletions Vertical wells Horizontal pad wells Frac Designs Resource is Widely Distributed 24

26 Bitumen 527 net sections (329,000 net acres) of oil sand leases Various formation targets and ultimate recovery methods 7 potential project areas with varying potential >3 Billion bbls OBIP independently recognized at Liege and Panny 278 MMbbl contingent resource 467 MMbbl additional prospective resource Perpetual OS Leases Primary Projects SAGD Projects Fireflood Projects CSS Projects Electric Heaters Oil Pipelines 25

27 Bitumen Marten Hill Clearwater Project Area Oil Sands Leases Horizontal Well 100/ W4/00 OOIP > 10m pay = 310 MMbbl Contingent Resource = 11.5 MMbbl Reconfigure W4M horizontal well Evaluating electrical field process for enhanced oil recovery Cold baseline test commenced late Feb 2013 ERCB approval for pilot received Joint Venture Secured - PMT Carried for Phase 1 Pilot Project Costs 26

28 Bitumen Panny Bluesky 8m Bitumen 10m Bitumen 2010/11 Vertical Wells Existing Horizontal Well Roads Natural Gas Pipeline Oil Well Effluent Pipeline Perpetual Gas Plant Perpetual Oil Sands Rights Other Perpetual Lands Established low rate flow without solvent or thermal assistance Average pay thickness 11 m Low viscosity bitumen ~15, o C Highly mobile at ~70 o C Panny Bluesky Resource Assessment (McDaniel P50) 755 MMbbl Discovered OBIP 132 MMbbl Contingent Resource 17.5% recovery factor applied utilizing horizontal cyclic steam Resource to support 15,000 bbl/d commercial project for 20 to 25 years Technology pilot pending Submitted ERCB application LEAD Electrical heat w water &/or solvent IETP funding approved Water source well drilled Excellent reservoir quality in Bluesky homogeneous shoreface sand facies 27

29 LEAD Process Technology Pilot Low pressure Electro-thermally Assisted Drive Pilot Plan $18.2 MM capital and operating costs over pilot life (3 years) IETP funding (30%) $5.5 million POB Production Facilities Producing Wellhead Power source Injection Facilities TOB1 TOB2 TOB3 Overburden Pay Zone Underburden Electrical Heating Cable with Water Injection for Mobility and Pressure Support 28

30 Bitumen Liege Carbonates R 22 R 21 R 20 R19 W4 T95 T94 T93 T92 Grosmont Net Bitumen m m >30m 3 Grosmont carbonate / Leduc OV wells drilled to evaluate resource Stacking of 3 Grosmont units > 30 m pay Leduc reef facies also present and bitumen saturated in places; geologically complex Resource Assessment (McDaniel best est.) 2,327 MMbbl bitumen in place (Undiscovered plus discovered) 132 MMbbl Contingent Resource assigned 449 MMbbl Prospective Resource assigned Increased in 2012 with technology improvements and greater well density 25% recovery factor applied using SAGD as technology under development T91 T90 Q OV Wells Perpetual Oil Sand Leases Leduc Reef Excellent reservoir quality vuggy porosity in Grosmont 29

31 Manage Downside Risk and Reduce Debt

32 Debt Reduction Debt Reduction While Executing Asset Base Repositioning Strategy 31

33 Dispositions 23 Transactions Closed in 2012 Net Proceeds: $167.2 MM Production: 2,945 Boe/d Gas: 13.2 MMcf/d Oil and NGL: 745 bbl/d P+P Reserves: 10.0 MMBoe Reduction in FDC: $24.6 MM Warwick Gas Storage: 90% 1 year option to buyback up to 30% TriOil shares: Sold 0.7 million Elmworth Sale Closed March 2013 Net Proceeds: $77.5 MM Production: 0 Boe/d P+P Reserves: 13.1 MMBoe Reduction in FDC: $122.8 MM ~$245 Million in Dispositions Negotiated in 2012 Targeting Additional $100 MM in Dispositions in Remainder of 2013 &

34 Diversification - 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 Compressor Facility Pipeline Horizontal Wells 2012 Hz Wells TCPL Pipeline Commercial Park and Loan business 30 to 50 year life Grass Roots Gas Storage Development Existing depleted gas pool Test Cycle Injection: Q2/Q Facility Construction Q2-Q > 200 MMcf/d withdrawal capacity Test Cycle Withdrawal: Q Bcf Cycle 2 and 3: Q Q Bcf 2012 operating cash flow $11 MM Expanded Working Gas Capacity with 2 wells Q Delta pressuring in 2013 Current Cycle: Q Q Bcf Perpetual owns 30% Interest Exercised buy back option for 20% repurchase in May 2013 ($19 MM) Manage WGS LP for annual fee Non-Depleting, Long Life, Diversifying Asset 33

35 Balance Sheet Current Net Bank Debt: $65 million Borrowing base on credit facility $110 million Next semi-annual redetermination October 2013 Senior Unsecured Notes: $150 million Coupon rate % Maturity date - March 2018 Convertible Debentures: $160 million Repayable with in cash or equity at Perpetual s discretion 2015 maturities Senior notes provisions should not restrict cash repayment Normal Course Issuer Bid in place TSX Symbol Amount Outstanding Coupon Rate Conversion Price Maturity Date 5 Day Weighted Avg. Trading Price PMT.DB.D $99.90 million 7.25% $7.50 January 31, 2015 $97.61 PMT.DB.E $59.88 million 7.00% $7.00 December 31, 2015 $96.26 Total Current Net Debt: $375 million Over 80% of Debt has Term into 2015 and Beyond 34

36 Commodity Price Risk Management Strategy Enhance or protect funds flow and balance sheet Enhance or protect the economics of an acquisition Enhance or protect capital program economics Capitalize on perceived market anomalies $180 $8.00 $160 $7.00 $140 $6.00 Hedging Gain/Loss ($Millions) $120 $100 $80 $60 $40 $20 $5.00 $4.00 $3.00 $2.00 $1.00 Gas Price ($/Mcf) $ E $- Hedging Gain/Loss Realized Natural Gas Price Including Hedging AECO-C - per Mcf Currently Exposed to Potential Gas Price Recovery in 2014 and Beyond Monitoring Supply / Demand Variables Closely 35

37 Commodity Price Risk Management Strategy Type of Contract Term Volumes (GJ/day) (bbl/d) Fixed or Floor Price ($/GJ) ($/bbl) Ceiling price ($/GJ) ($/bbl) Futures Price ($/GJ) ($/bbl) (1) % of 2013E Gas or Oil & NGL Production (2) AECO Fixed Price September ,000 $ $ % AECO Fixed Price October ,000 $ $ % AECO Fixed Price November ,000 $ $ % AECO Fixed Price December ,000 $ $ % WTI collars Sept-Dec ,250 $88.40 $ $ % WTI collars Calendar ,500 $86.67 $95.15 $ % WTI Fixed Price September $ $ % WTI-WCS Differential WTI-WCS Differential Sept-Dec ,250 US ($22.79) - US ($25.00) 56% Calendar US ($23.00) - US ($23.75) 12% 1) Aug 28, 2013 prices 2) Calculated using forecasted 2013 oil and NGL production of 4,050 bbl/d and 120,000 GJ/d of actual and deemed gas production Both Oil and Gas Price Management Strategies in Place 36

38 Prepare to Maximize Value from Shallow Gas Assets in Gas Price Recovery

39 Conventional Shallow Gas East Central and Northeast Alberta Belly River Viking Grand Rapids Lower Mannville Pre Cretaceous Unconformity Cretaceous and Devonian sweet shallow gas Current production: ~70 MMcf/d Base declines < 20% Multiple stacked zones and play types Extensive plant and pipeline infrastructure with large fixed cost component Low base royalty rate Average 5% at <~$5/Mcf 740 Uphole recompletions awaiting depletion of producing zones Low cost production and reserves adds (<$10,000/boe/d; <$1.00/Mcf) Focused on fixed operating cost reductions Office consolidation, metering, municipal taxes Cash Flow and Value Highly Leveraged to Gas Price Recovery 38

40 Investment Thesis

41 Strong Annual Growth Forecast 2013 Flat year over year E&D capital spending at ~$75 - $85 million Oil and NGL production growth of 10 to 15% Resource-style deep basin gas production growth of >20% Funds flow and funds flow per share growth of 20% (@ current strip) 10 % debt reduction from year end Preliminary forecast for similar level of year over year funds flow growth 20-40% growth over 2013 estimates with either gas or oil weighted drilling program Tremendous leverage to further gas price recovery Every $0.50 per Mcf = $15 million of annual funds flow (25% increase) Year over Year Growth Forecast in Focus Areas 40

42 Sum of the Parts $1, Unrisked NAV $6.89 /Share (2) $8.00 Warwick Gas Storage $1, Viking/Colorado Shallow Shale Gas NPV 8% ($MM) $ $ $ Reserve-Based NAV $2.04 /Share (1) Risked NAV $4.14 /Share (2) $6.00 $4.00 $2.00 $ / Share Conventional Shallow Gas Wilrich Bitumen Mannville Heavy Oil Gas Over Bitumen TriOil Hedge Book Proved + Probable Developed $0.00 $0 Proved + Probable Undeveloped Bank Debt Senior Notes -$ $2.00 Convertiable Debentures Net ARO -$ Liabilities Assets Risked Assets UnRisked -$4.00 (1) McDaniel Reserves and Pricing, Adjusted for Elmworth disposition (2) Prospect Inventory Internal Assessment; McDaniel year-end pricing Trading at ~1/2 of Reserve-Based Net Asset Value 41

43 PMT Investment Thesis Asset base repositioning for resource-style oil and NGL diversification successful Mannville heavy oil delivering results with material secondary recovery growth potential Edson Wilrich liquids-rich gas inventory proven and highly economic Execution and operational excellence in chosen strategies Increasing oil and NGL in commodity mix growing funds flow >80% of debt has term into 2015 providing flexibility Asset dispositions and growing cash flow improving debt to cash flow ratios 50% drawn on credit facility (pro-forma Warwick gas storage buyback) Pursuing further asset dispositions to continue to reduce outright debt leverage Multiple levers available to further manage balance sheet High impact value potential from medium to long term portfolio of assets Tremendous leverage to any gas price cycle recovery in 2013 and beyond Trading significantly below Produce-Out Net Asset Value Spectrum of Opportunity to Grow and Prosper 42

44 Important Information about the Presentation Non-GAAP Measures This presentation contains financial measures that may not be calculated in accordance with generally accepted accounting principles ("GAAP"). Readers are referred to advisories and further discussion on non-gaap measures contained in the "Non-GAAP Measures" section of our most recent management's discussion and analysis. IP rates Initial production or IP rates contained in this presentation are based the length of the specific production tests disclosed herein and are not necessarily indicative of long-term performance or ultimate recovery. Initial production rates disclosed herein are based on 3 days of initial production and are not necessarily indicative of long-term performance or ultimate recovery. Financial Outlooks Included in this presentation are estimates of Perpetual's future cash flow and debt levels, which are based on the various assumptions as to production levels, capital expenditures, commodity prices and other assumptions disclosed in this presentation. To the extent such estimates constitute a financial outlook, they were approved by management of Perpetual on April, 2012 and are included to provide readers with an understanding of Perpetual's anticipated financial position and readers are cautioned that the information may not be appropriate for other purposes. Reserves, Resource and F&D Disclosure Unless as otherwise noted, reserves and resource information included in this presentation is based on independent evaluations prepared by McDaniel and Associates Consultants Ltd. in accordance with National Instrument ("NI ") using McDaniel's forecast prices and costs. All of Perpetual's contingent resources currently have an "undetermined" economic status as sub-classification into economic and uneconomic categories has not been evaluated. Contingencies affecting the classification of the resources include corporate development plans, the need for regulatory approval, and the need to perform an economic study regarding production. There is no certainty that it will be commercially viable to produce any portion of the resources. Please refer to "Notes Pertaining to the Reporting of Bitumen Contingent Resource" in Perpetual's February 8, 2012 press release and Perpetual's most recent Annual Information Form for applicable definitions and risk factors pertaining to Perpetual's reserve and resource disclosure. Perpetual's F&D cost as well as finding, development and acquisition costs, before and after the inclusion of changes in future development capital are disclosed under the heading "Finding, Development and Acquisition ('FD&A') Costs" in Perpetual's February 8, 2012 press release. Please refer to this press release for additional disclosure pertaining to Perpetual's F&D costs. The aggregate of exploration and development costs incurred in the most recent financial year and the change in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year. Projected Economics This presentation includes estimates of projected economics or value potential for Perpetual's Mannville heavy oil and West Edson Wilrich liquids rich gas assets. Estimates of "projected capital", "NPV@10%", "ROR", "F&D", "capital efficiency" and "recycle ratio" are provided in respect of these assets. These terms referenced in this presentation are estimates by Perpetual of future results based on the indicated assumptions and are by their nature projections which are different than terms calculated in accordance with NI , which are historical calculations. These estimates have been provided as Perpetual believes they provide a reasonable estimate of the future economics of Perpetual's Mannville heavy oil and West Edson Wilrich liquids rich gas value. These terms do not have a standardized meaning prescribed by NI , the COGE Handbook or CSA Notice and therefore these measures, as defined by Perpetual, may not be comparable to similar measures presented by other issuers. These estimate constitute forward-looking information and therefore reflects several material factors, expectations and assumptions and is subject to a number of risk factors. See "Forward-Looking Information" above for further information. Mcf equivalent (Mcfe) Mcf equivalent (Mcfe) may be misleading, particularly if used in isolation. In accordance with NI a Mcfe conversion ratio for oil of 1 Bbl: 6 Mcf has been used, which is based on an energy equivalency conversion method primarily applicable at the burner tip and does not necessarily represent a value equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. Net Asset Value In relation to the disclosure of net asset value ("NAV") in this presentation, the NAV presented herein is what is normally referred to as a "produce-out" NAV calculation under which the current value of Perpetual's reserves would be produced at forecast future prices and costs and do not necessarily represent a "going concern" value of our company. The value is a snapshot in time and is based on various assumptions including commodity prices and foreign exchange rates that vary over time. It should not be assumed that the NAV represents the fair market value of Perpetual.

45 FOR ADDITIONAL INFORMATION: Susan L. Riddell Rose President & CEO Cameron R. Sebastian Vice President, Finance & CFO 3200, Avenue SW Calgary, Alberta CANADA T2P 3H TOLL FREE PHONE FAX info@perpetualenergyinc.com perpetualenergyinc.com