CIBC Conference April 16, 2013
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 forward-looking 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 four strategic priorities for 2012; and diversification strategy scenarios for 2012 to 2015. 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 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 effects on our business and operations and on the forward-looking statements contained herein. 1 1
Market Profile TSX:PMT Common shares outstanding 147.7 million Management ownership 25.4% Share price (5 day weighted average) $ 1.12 Market capitalization $ 165 million Convertible debentures (PMT.DB.D; PMT.DB.E) Senior unsecured notes Net bank debt Total Net Debt $ 160 million $ 150 million $ 40 million $ 350 million Enterprise value $ 515 million 30 day weighted average daily trading volume ~ 210,000 shares/day Total Net Debt ~$350 Million 2
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
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 Actual & Deemed Production (March 2013) Natural Gas (81%) NGL s and Oil (19%) Gas over Bitumen Deemed Production (1) P+P Reserves (3) Reserve to Production Ratio (P+P) (RLI) Contingent Resource Bitumen (2) Warwick Gas Storage Working Gas Capacity (gross) (4) 23,000 Boe/d 90 MMcf/d 3,700 bbl/d 25.0 MMcf/d 449 Bcfe 11.0 Years 279 MMbbl 19-22 Bcf (1) Cash Flow = 0.5 x [(deemed production volume x 0.80) x (Alberta Reference Price - $0.3791/GJ)] (2) Best estimate as evaluated by McDaniel (3) As evaluated by McDaniel at year end 2013 (4) 10 % ownership interest with option to increase to 40% 4
Diversified Portfolio Built to Prosper SHALLOW GAS LIQUIDS- RICH GAS HEAVY OIL BITUMEN OTHER Maximize Cash Flow Invest For Growth Invest For Growth Advance and Optimize For Value Advance and Optimize For Value Eastern Alberta Conventional Viking/Colorado Shallow Shale Gas Edson Wilrich HZ Greater Edson Multi-zone Mannville Heavy Oil Exploration Panny Bluesky Marten Hills Clearwater Liege Grosmont and Leduc Other Warwick Gas Storage (10%) GOB Technical Solutions TriOil Shares Tight Oil & Gas Exploration Spectrum of Opportunities to Invest In Through Variable Commodity Cycles 5
Portfolio Management Strategy CASH FLOW GENERATORS Maximize Cash Flow Conventional Shallow Gas Warwick Gas Storage PROVEN DIVERSIFYING GROWTH STRATEGIES Invest For Growth Eastern Alberta Heavy Oil Edson Liquids-Rich Wilrich + Gas + MEDIUM AND LONG TERM VALUE STRATEGIES Optimize and Advance Viking/Colorado Shale Gas Bitumen Panny Bluesky Marten Hills Clearwater Liege Carbonates GOB Technical Solutions Tight Oil & Gas Exploration Entrepreneurial Approach to Value Creation 6
Asset Base Transformation Resource-style oil & NGL-rich growth assets now represent 40% of production 75% increase in oil and NGL production in 2012 to 3,448 bbl/d Deep basin gas increased 15% in 2012 to 24.1 MMcf/d Preferential capital spending on oil and NGL-rich gas projects expected to increase a oil and NGL s a further 19% to 4,100 bbl/d Forecast to average >20% oil and NGL s in 2013 Eight Fold Increase in Production from Resource-Style Growth Assets 7
Q110 Q210 Q310 Q410 Q111 Q211 Q311 Q411 Q112 Q212 Q312 Q412 Q113E Q213E Q313E Q413E Revenue ($MM) Cash Flow Diversification 30 Revenue from Oil and NGLs 60% Oil and liquids contributed close to 50% of revenue in 2012, double the contribution of the previous year 25 50% 20 40% Aggressive hedging led to gains representing15% of revenue 15 30% 10 20% 2012 Revenue 5 10% Oil Hedging 0 0% Gas storage NGL Oil and NGL Revenue Oil and NGL % of Total Revenue Gas 311% Increase in Oil and Liquids Revenue and Growing 8
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 5. Prepare to Maximize Value from Shallow Gas in Gas Price Recovery Positive Momentum on All Fronts 9
Maximize Value of Mannville Heavy Oil
Eastern Alberta - Conventional Heavy Oil Mannville Q1 16 drills ~3D coverage Q3 12 drills Q1 10 drills Discovered 12 Mannville pools 6 Lloyd, 5 Sparky, 1 Basal Quartz > 200 MMbbl Original Oil in Place (1) > 10 MMbbl @ 5% recovery factor (1) Current Production ~ 3,400 bbl/d Low cost HZ development HZ $ 1.1 MM single lateral well $1.4 MM for multi-lateral well Average initial rate over 100 bbl/d Extensive in-house 3D & 2D seismic 123,000 net acres of lands 2013 Q1 Activity 26 gross (24.7 net) drilled to date Evaluating downspacing and multi-laterals 1 new pool being evaluated outside Mannville 2013 H2 Activity Up to 12 gross (11.3 net) Planning for 2014 EOR execution Inventory of Over 120 Locations at Varying Stages of Drill Readiness 11
Daily Oil Production (bbl/d) Heavy Oil Production Mannville Heavy Oil Production 4,500 2012 Capital Program 4,000 3,500 3,000 2013 Capital Program BASE 3,700 bbl/d 2,500 2013 Capex $49.3 MM 2,000 2012 Capex $45.6MM 1,500 1,000 500 0 Jan 12 Feb 12 Mar 12 Apr 12 May 12 Jun 12 Jul 12 Aug 12 Sep 12 Oct 12 Nov 12 Dec 12 Jan 13 Feb 13 Mar 13 Apr 13 May 13 Jun 13 Jul 13 Aug 13 Sep 13 Oct 13 Nov 13 Dec 13 Production on Track 12
Oil Rates, bbl/d Upper Mannville A Pool Lloyd Channel OOIP = 33 MMbbls Cumulative to date 530 Mbbls year end 2012 ( ~ 1.6% recovery) Booked Reserves (year end 2012) 1.13 MMbbl (5% RF) 7 wells drilled in 2012; 3 wells planned 2013 4 additional locations in inventory based on 100 m spacing Evaluating 50m infills 400 HZ Wells Production vs. Type Curves 350 02/14-25-050-09W4/0 300 03/14-25-050-09W4/0 LLOYD CHANNEL TYPE LOG 100/04-36-050-09W4/00 250 200 00/01-36-050-09W4/0 02/01-36-050-09W4/0 00/08-36-050-09W4/0 02/08-36-050-09W4/0 150 2012 Type curve 100 2013 Type Well 00/16-27-050-09W4/0 50 00/09-36-050-09W4/0 0 0 10000 20000 30000 40000 50000 60000 70000 80000 90000 100000 110000 Oil Cumulative, bbl Wells Generally Performing At or Above Type Curve 13
Sparky New Developments 00/14-29 SPARKY MID TYPE LOG 100/02-14-049-07W4/00 > 24 % DENSITY POROSITY 4 m OIL PAY Mid Sand 00/03-20 00/13-16 02/13-16 02/12-16 00/05-16 2012 DRILL 2013 DRILL 02/14-14 00/14-14 02/11-14 00/11-14 02/08-14 02/01-14 Regional Sparky Pool OOIP = 34.4 MMbbl Cumulative to date 34 Mbbl (12/31/12) 5 wells drilled in 2012 10 drilled in Q1 2013 2 multi-laterals Evaluating secondary and EOR recovery 18 Locations in Inventory Based on 200m Spacing / 30 at 100m Spacing 14
Mannville Heavy Oil Value Potential Capital (D,C & T) NPV @ 10 % Projected Economics per Drilling Location $1.1 MM $ 1.049 MM ROR 105 % F&D $16.00 /Boe Pricing Operating Costs Type Curve Assumptions (from McDaniel) $92.50/bbl WTI; $26.90/bbl 2013 differential = $ 65.60 Hardisty heavy price $10.56 /Boe (first year), $23 / Boe (lifetime) IP 70 bbl/d, 1 year exit rate 44 bbl/d Capital Efficiency ~$20,138 Boe/d Reserves 70.5 Mbbl per well (economic limit) 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 15
Oil Rates ( bbl/d) Upper Mannville I2I Pool Regional Sparky 00/10-32 02/8-4 00/2-4 00/01-04 OOIP = 29 MMbbls Cumulative to date 352 Mbbls Recovery Factor to date 1.2 % - Expect 5-8% on Primary 2012 drilled 2-100 m infills 2013 plan to drill 5-6 additional 100m infills Preparing for implementation of Water/Polymer flood in 2014 00/08-32 00/5-33 00/15-28 350 300 Upper Mannville I2I HZ Wells Production vs. Type Well 00/01-28-050-08W4/0 00/02-28-050-08W4/0 00/03-28-050-08W4/0 2012 DRILL 2013 DRILL SPARKY MID TYPE LOG 100/09-32-050-08W4/00 > 24 % DENSITY POROSITY 6 m OIL PAY Mid Sand 250 200 150 100 50 0 00/16-32-050-08W4 02/16-32-050-08W4 00/13-33-050-08W4 02/13-33-050-08W4 00/14-33-050-08W4/0 00/15-33-050-08W4/0 02/04-04-051-08W4/0 03/04-04-051-08W4/0 Oil Type Well 00/08-32-050-08W4/0 0 10000 20000 30000 40000 50000 00/01-04-051-08W4/0 60000 70000 Oil Cumulative (bbl) Enhanced Recovery Scheme Projected to Increase Recovery to 10-15% 16
Enhanced Oil Recovery Scope (Select pools) Pool Name 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 (MMbbl) (MMbbl) (MMbbl) (MMbbl) (MMbbl) Sparky I2I 29 0.33 0.59 (3) 4.1% (3) 1.5 2.3 2.9 4.4 Upper Mannville A (2) 29 0.32 0.71 3.6% 1.5 2.3 2.9 4.4 Upper Mannville B (2) 14 0.14 0.37 3.6% 0.7 1.1 1.4 2.1 Sparky O 34 0.034 0.44 1.4% 1.7-2.7 3.4-5.1 Total 106 0.82 2.10 2.3 % 5.3 8.5 10.6 15.9 (1) Internal estimate (2) Portion of entire pool (3) Net reserves at 66.67% WI, recovery factor adjusted to gross 17 Significant Scope for Increased Reserves & Value With Infill Drills, Water & Polymer Floods
Position for Growth of Edson Liquids-Rich Gas
Edson Wilrich Liquids-Rich Gas West Edson Facility Expansion to 30 MMcf/d completed Pipeline to Alliance to be constructed Q2/Q3 2013 10 Pipeline To Edson Deep Cut Plant 36 bbl/mmcf NGLs net sections of additional Wilrich Rights Added in Q1 16-10 Compressor Capacity 30 MMcf/d 1-34 Compressor compressor expansion to 30 MMcf/d Q2/Q3 Refrig and Sales P/L to Alliance Edson Vertical Well Pre-2012 Horizontal Well 2012 Horizontal Well West Edson 2012 Q4 / 2013 Q1 Activity 2012 Q4 Hz Well 2013 Planned Hz Well West Edson Trunk Line and Facility Expansion to 30 MMcf/d Completed 10 Net Sections of Additional Wilrich Rights Added in Q1 19
West Edson Production Added > 3,000 boe/d at West Edson in 1.5 Years 20
Wilrich Value Potential - Edson Projected Economics per Drilling Location Assumptions (McDaniel) Capital (D,C & T) $ 4.9 MM Pricing $3.18 / GJ 2013; $61.00 /bbl NGLs 3.35/mmbtu NPV @ 10 % $ 1.949 MM Operating Costs $5.50/ BOE (first year) ROR 40 % BT Well Depth 4,000 M HZ; 2,400 TVD F&D $11.91 / BOE Type Curve IP 4 MMcf/d, 1 year exit rate 1.2 MMcf/d 33.5 bbls/mmcf NGL s/condensate Capital Efficiency Recycle Ratio 2.04 <$13,138 BOE/d (first twelve months) Reserves Royalties Risk 2.46 Bcfe per well 5% royalty until credit of ~$2mm is used Unrisked Testing Flare from 14-28 Wilrich HZ 13-5 Wilrich HZ Frac South Edson Extension Exceeding Type Curve Inventory of 64 Net Locations at 2 Wells per Section Modeling Work Supports Further Doubling of Inventory through Downspacing 21
Wilrich Value Potential - West Edson Projected Economics per Drilling Location Assumptions (McDaniel) Capital (D,C & T) $6.3 MM gross Pricing $3.18 / GJ 2013; $57 /bbl NGLs 3.35/mmbtu NPV @ 10 % $ 4.93 mm BT Operating Costs $4.75 / BOE (first year) ROR 200 % BT Well Depth 4,200 M HZ; 2,700 TVD F&D $ 9.92 / BOE Type Curve IP 12.0 MMcf/d, 1 year exit rate 1.5 MMcf/d 32 bbls/mmcf NGL s/condensate Capital Efficiency < $12,840 BOE/d Recycle Ratio 2.95 Testing Flare from 8-17 Wilrich Hrztl Reserves Royalties Risk West Edson Compressor Station 3.8 Bcfe per well 5% royalty until credit of ~$2.7 mm is used Unrisked Newest Wells Exceeding Type Curve Inventory of 32 Net Locations at 2 Wells per Section 22
2013 Capital Budget Vast Majority of Capital in Q1 Q1 Directed 2013 (1) to Mannville Heavy Remainder Oil 2013 Flexibility in remainder of year Wells to execute Capital Wilrich or Wells Mannville Capital inventory Mannville Heavy Oil 27 gross (1) (25.7 net) ($MM) $27.5 ($MM) 0-12 gross (0-11.3 net) $3.0-17.8 27-39 gross (25.7 37.0 net) Total 2013 Wells Capital ($MM) $30.5-45.3 West Central Wilrich 3 gross (2) (2 net) $5.2 2-6 gross (1-3.5 net) $6.5-20.4 5-9 gross (3.0-5.5 net) $11.7 25.6 West Central Facilities $5.2 $ 7.1 $12.3 Abandonment and reclamation Land, Seismic and Other $0.4 $1.4 $1.8 $1.7 $2.5 $4.2 Total $40 MM $35 MM ~$ 75 MM 1) Completion and facility operations for the 27 wells carried into Q2 2) Well count is for completion and gathering and equipping 2012 Q4 drills Capital Highly Focused on Oil and NGL Production Growth 23
Optimize and Advance Medium to Long Term Opportunities Elmworth Montney Viking/Colorado Shallow Shale Gas Bitumen
Elmworth Montney 92 Gross Sections of Montney Exposure 50/50 Joint Venture with Tourmaline Reserves and Contingent Resource Close to 4 Tcf OGIP (internal estimate) >1 Tcf gross OGIP in Montney B recorded by McDaniel 42 Bcfe net P+P reserves booked 136 Bcfe net best estimate additional contingent resource 34 gross (17 net) sections not yet evaluated (SW Wapiti Block) Technical Viability of Play Confirmed Over 20 competitor wells drilled & on production Extensive drilling programs surrounding acreage ongoing IP (1 month) of offset HZ wells 3 to 6 MMcf/d 3 Perpetual-interest wells tested 6 to 8 MMcf/d/well Recombined free liquids and NGLs ~ 20 bbl/mmcf condensate plus 25 to 45 bbl/mmcf NGLs (processing dependent) 2% H 2 S Perpetual Locations Montney Producers Perpetual Lands Long Term Sour Resource Development Project Processing Infrastructure Construction Required 25
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/well gross Unbooked Additional Rec. Resource 50+ Bcf lost due to price revisions Colorado Resource Potential Average 435 MMcf/well gross Expected horizontal development plan at 8 wells per section 1.6 Tcf Potential Recoverable Resource Over 475 sections of unbooked Viking and Colorado potential Extensive plant and pipeline infrastructure Develop Viking tight sand and Colorado Group shale together to reduce costs, increase recovery and enhance economics 26
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 2011-2012 Advanced detailed (3G) technical study Gas in Place, brittleness mapping, production inflow and fracture modeling Pilot work evaluated fracture performance through recompletions 2013 Monitor industry horizontal development pilot 8 well HZ pilot execution planning Resource is Widely Distributed 27
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 Perpetual OS Leases Primary Projects SAGD Projects Fireflood Projects CSS Projects Electric Heaters Oil Pipelines 28
Bitumen Panny Bluesky 8m Bitumen 10m Bitumen 2010/11 Vertical Locations 2010/11 Horizontal Locations Established low rate flow without solvent or thermal assistance Average pay thickness 11 m Low viscosity bitumen ~15,000 cp @ 25 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 Submitted ERCB application for pilot test LEAD electrical heat with water and/or solvent IETP funding pending Excellent reservoir quality in Bluesky homogeneous shoreface sand facies Roads Natural Gas Pipeline Oil Well Effluent Pipeline Perpetual Gas Plant Perpetual Oil Sands Rights Other Perpetual Lands 29
LEAD Process (Low pressure electro-thermally assisted drive) 13-34 POB Production Facilities Producing Wellhead Power source Injection Facilities TOB1 TOB2 TOB3 Overburden Pay Zone Underburden Shale Gas Cap Injected Water Heater Well 15-18 m + Appx 4 m Injected Water Heater Well Prod Well Shale Electrical Heating Coils with Water Injection Provide Mobility and Pressure Support 30
Bitumen Liege Carbonates T95 T94 T93 R 22 R 21 R 20 GROSMONT NET BITUMEN 10-20 m 20 30 m >30 m R19 W4 3 Grosmont carbonate / Leduc wells drilled in Q1 2011 to evaluate resource Stacking of 3 Grosmont units > 30 m pay Leduc reef facies 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 T92 T91 T90 T89 Q1 2011 OV Wells Perpetual Oil Sand Leases Leduc Reef Excellent reservoir quality vuggy porosity in Grosmont 31
Bitumen Marten Hill Clearwater PROJECT AREA OIL SANDS LEASES RECONFIGURATION WELL 100/08-30-075-25W4/00 OOIP > 10m pay = 310 MMbbl Contingent Resource = 11.5 MMbbls Reconfigure 3-30-75-25 W4M horizontal well Evaluating electrical field process on oil recovery Cold baseline test commenced late Feb ERCB approval for pilot received Entered into joint venture with ElectroPetroleum Inc. EPI pays 100% for reconfiguration and first phase of pilot 32
Manage Downside Risk
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: 11.3 MMBoe Change in FDC: $24.6 MM Warwick Gas Storage: 90% 1 year option to buyback up to 30% TriOil shares: Sold 0.66 million Elmworth Sale Closed March 2013 Net Proceeds: $77.5 MM Production: 0 Boe/d P+P Reserves: 13.1 MMBoe Change in FDC: $122.8 MM ~$245 Million in Dispositions Negotiated in 2012 34
Warwick Gas Storage 40 Bcf Storage Reservoir 10 Bcf base reserves cushion gas in place 5-11 Bcf additional operating cushion 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 Commercial Park and Loan business Grass Roots Gas Storage Development Existing depleted gas pool Test Cycle Injection: Q2/Q3 2010 Facility Construction Q2-Q4 2010 > 200 MMcf/d withdrawal capacity Test Cycle Withdrawal: Q1 2011 7.8 Bcf Cycle 2 and 3: Q2 2011 Q1 2013 17 Bcf Current Cycle: 19-22 Bcf 2012 operating cash flow $11 MM Expansion with 2 wells Q4 2012 Delta pressuring planned for 2013 30 to 50 year life Non-Depleting, Long Life, Diversifying Asset 35
Warwick Joint Venture and Option Sale of 90% partnership interest in Warwick Gas Storage in April 2012 Option to buyback up to an additional 30% equity interest prior to April 25, 2013 ~$30MM Option purchase price reflects pro-rata disposition price plus pro-rata capital spending less distributed cash flow plus adjustments One year option allows Perpetual to assess: Natural gas market and spreads Reservoir performance Expansion project performance with new wells and delta pressuring Balance sheet Other capital investment opportunities Perpetual Operates Asset and Manages WGS LP for Annual Fee 36
Gas Price $/Mcfe $ Millions 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 $9.00 $8.00 $7.00 $6.00 $5.00 $4.00 $3.00 $2.00 $1.00 180 160 140 120 100 80 60 40 20 - $0.00 2008 2009 2010 2011 2012 2013E (20) Hedging Gain/Loss Realized Natural Gas Price Including Hedging AECO-C - per mcf Currently Exposed to Potential Gas Price Recovery in 2013 and Beyond Monitoring Supply/Demand Variables Closely 37
Commodity Price Risk Management Strategy Type of Contract Term Volumes (GJ/day) (bbl/d) Fixed or Floor Price ($/GJ) ($/bbl) Ceiling price ($/GJ) ($/bbl) Futures Price ($/GJ) ($/bbl) (1) % of 2013E Gas or Oil & NGL Production (2) AECO Fixed Price June 2013 72,500 $3.53 - $3.57 57% AECO Fixed Price July Dec 2013 37,500 $3.60 - $3.72 30% WTI collars Calendar 2013 2,250 $88.40 $100.76 $91.37 65% WTI collars Calendar 2014 1,000 $85.00 $91.15 $90.19 29% WTI-WCS Differential Calendar 2013 2,250 US $22.79 - US $21.00-1) April 12, 2013 prices 2) Based on 2012 last closed quarter production Both Oil and Gas Price Management Strategies in Place 38
Balance Sheet Current Net Bank Debt: ~$40 million Borrowing base on credit facility - $127.5 million Next semi-annual redetermination - April 30, 2013 Senior Unsecured Notes: $150 million Coupon rate - 8.75% Maturity date - March 2018 Convertible Debentures: $160 million Repayable with bank debt or equity at Perpetual s discretion Effectively long term debt with 2015 maturities Senior notes provisions should not restrict cash repayment TSX Symbol Amount Outstanding Coupon Rate Conversion Price Maturity Date 5 Day Weighted Avg. Trading Price PMT.DB.D $ 100.0 million 7.25% $ 7.50 January 31, 2015 $ 94.70 PMT.DB.E $ 60.0 million 7.00% $ 7.00 December 31, 2015 $ 94.29 Total Current Net Debt: ~$350 Net Bank Debt ~$40 million 39
Debt Reduction Birchwavy Acquisition - $130 MM $600 $500 Office Building Sale - $36 MM Elmworth Montney - $19 MM Profound Acquisition - $81 MM 2012 Disposition Proceeds - $147 MM $75 MM Debenture Repayment Edson Acquisition - $71 MM 2013 Disposition Proceeds - $77. 5 MM Wilrich (Elmworth) $600 GOB Shut-In Reserves Sale - $40 MM Capex Expansion - $50 MM Wilrich/Mannville $500 $400 $400 $300 $300 $200 $200 $100 $100 $0 2007 2008 2009 2010 2011 2012 2013E (1) Net Bank Debt Convertible Debentures New Debenture Issue Bank Debt for Acquisitions Senior Notes (1) Bank Debt Adjusted for Accounts Receivable, Marketable Securities and Accounts Payable $0 Debt Reduction While Executing Asset Base Repositioning Strategy 40
Prepare to Maximize Value from Shallow Gas Assets in Gas Price Recovery
Conventional Shallow Gas East Central and Northeast Alberta Belly River Cretaceous and Devonian sweet shallow gas Current production: 70-75 MMcf/d Viking Base declines < 20% Multiple stacked zones and play types Grand Rapids Lower Mannville Pre Cretaceous Unconformity 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; <$1.00/Mcf) Cash Flow and Value Highly Leveraged to Gas Price Recovery 42
Investment Thesis
NPV 8% ($MM) Sum of the Parts (Risked & Unrisked) $1,000.00 $6.80 $750.00 Unrisked NAV @ 8% $5.34 / Share $5.10 Warwick Gas Storage Viking/Colorado Shallow Shale Gas Conventional Shallow Gas Wilrich $500.00 Risked NAV @ 8% $3.00 / Share $3.40 Bitumen Mannville Heavy Oil $250.00 Reserve Based NAV @ 8% $2.04 / Share $1.70 Gas Over Bitumen TriOil Hedge Book $0.00 $0 Proved + Probable Developed (Excluding Elmworth) Proved + Probable Undeveloped (Excluding Elmworth) Bank Debt -$250.00 -$1.70 Senior Notes Convertiable Debentures -$500.00 McDaniel Reserves and Pricing Prospect Inventory Internal Assessment Liabilties Assets Risked Assets UnRisked -$3.40 Net ARO Trading at ~1/2 of Produce-Out Net Asset Value 44
PMT Investment Thesis Asset base repositioning for resource style oil and liquids-focused opportunities successful Mannville heavy oil delivering results and has material secondary recovery growth potential Edson Wilrich liquids-rich gas inventory proven and growing Proven Execution Excellence in chosen strategies Increasing oil and liquids in commodity mix growing funds flow >80% of debt has term into 2015 providing flexibility Growing cash flow through diversification strategy improving debt to cash flow ratios Multiple levers available to further manage balance sheet 30% drawn on credit facility Tremendous leverage to any gas price cycle recovery in 2013 and beyond Every $0.50 per Mcf = $15 million of annual funds flow (25% increase) High impact value potential from spectrum of long term resource-style plays Currently trading at ~1/2 of Produce-Out Net Asset Value at strip pricing Spectrum of Opportunity to Grow and Prosper 45
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 51-101 ("NI 51-101") 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 51-101, 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 51-101, the COGE Handbook or CSA Notice 51-324 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 51-101 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. 46
perpetualenergyinc.com FOR ADDITIONAL INFORMATION: Susan L. Riddell Rose President & CEO Cameron R. Sebastian Vice President, Finance & CFO 3200, 605 5 Avenue SW Calgary, Alberta CANADA T2P 3H5 800.811.5522 TOLL FREE 403.269.4400 PHONE 403.269.4444 FAX info@perpetualenergyinc.com EMAIL 47