Perpetual Energy Inc. CIBC 2011 Energy & Infrastructure t Conference April 12, 2011
Disclaimer Cautionary Statement Regarding Forward-Looking Information This presentation contains forward-looking statements relating to Perpetual s operations that are based on management s current expectations, estimates and projections about its operations. Words and phrases such as anticipates, expects, believes, estimates, projected, future, goals, forecast, plan, opportunities, upside. will, impact, target, 2010 through 2014 and similar expressions are intended to identify such forward-looking statements. 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. The reader 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, t t 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; further 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 the current weak 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; a further write down 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 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 promulgated by rule-setting bodies; the transition to IFRS and its impact on our financial results; cash dividends or distributions, and the funding and tax treatment thereof; 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, expectations and objectives for future operations; and the factors set forth under the heading Risk Factors incorporated by reference from our Annual Reports, our Annual Informational Forms, our Quarterly Reports and our other filings on SEDAR. Unpredictable or unknown factors not discussed herein also could have material adverse effects on forward-looking statements. 1
Market Profile Common shares outstanding 148.3 million Management ownership 21% Share price (5 day weighted average) $ 4.20 Market capitalization $ 615 million Convertible debentures $ 235 million Senior unsecured notes $ 150 million Net bank debt $ 90 million Enterprise value $ 1.1 billion Current dividend (monthly) $ 0.03 per share Current annualized yield 9% Average daily trading volume 500,000 shares Corporate Conversion from Paramount Energy Trust completed July 1, 2010
Sustainable Growth Plus Income Strategy DIVIDENDS: Target a Sustainable Dividend BASE CASH FLOW GENERATORS: Target to Minimize Production Declines and Maximize Free Cash Flow HIGH IMPACT RESOURCE PLAYS : Target Growth And Cash Flow Diversification SYNERGISTIC ENTREPRENEURIAL IDEAS: Target Value And Cash Flow Diversification Targeting a sustainable cash flow distributing plus growth model
Assets and Operations
Entrepreneurial Approach to Value Creation CONVENTIONAL ASSETS Cash Flow Generators RESOURCE PLAYS Growth, Diversification and Value OPTION VALUE Synergistic Entrepreneurial Value Legacy Conventional shallow gas in northeast & east central Alberta Emerging g Conventional heavy oil + + Deep basin liquids-rich tight gas Edson liquids-rich Wilrich gas Pembina Cardium tight oil Elmworth Montney gas Viking /Colorado shallow shale gas NE Alberta bitumen/heavy oil Warwick Gas Storage NE Alberta bitumen thermal extraction GOB technical solutions or sales Tight oil & gas exploration TriOil Resources (4%) = Shareholder Value 5
Asset Overview Conventional Projects Cash Flow Generators Conventional Shallow Gas Conventional Heavy Oil 86% of production in 2010 to 75% in Q1 2011 Resource Projects Diversification and Growth Deep Basin Liquids Rich Gas Wilrich liquids rich gas Pembina/Carrot Creek Cardium tight oil Viking/Colorado tight shallow gas Elmworth Montney liquids rich gas NE Alberta Bitumen 14% of production in 2010 to 25% in Q1 2011 Gas Storage Project Diversification and Value Warwick Gas Storage Diverse portfolio of high impact opportunities supported by cash flow generators 6
Conventional Projects - Shallow Gas East Central and Northeast Alberta Cretaceous and Devonian sweet shallow gas Belly River Viking Grand Rapids Lower Mannville Pre Cretaceous Unconformity Base declines < 20% Multiple stacked zones and play types 1,000+ uphole recompletions awaiting depletion of producing zones Low cost production and reserves adds (<$10,000/BOE/d; <$1.00/Mcf) Typically ~150 recompletions per year 500+ new drill prospects Seismic definition and step out of infrastructure drive prospects to drill ready Historical drilling success > 90% Multi-zone drills generally convert to reserves in 1 or 2 zones with additional zones captured as uphole completions in prospect inventory ~10-20 new drills per year - best return and strategic only Average well $0.4 MM D C & E once established as drill ready Risked IP 300 Mcf/d; EUR 0.3 Bcf (<$25,000/BOE/d; <$1.77/Mcf) Extensive inventory of opportunities to minimize production declines at industry-leading capital efficiencies 7
Conventional Projects Heavy Oil R10 R8W4 New heavy oil focus utilizing in-house 3D & 2D seismic data and existing lands T52 T50 T48 Mannville 2011: 20-40 wells Viking-Kinsella 2011: 6-10 wells (50% WI) Exploration through recompletion of existing gas wells Mannville Area Development Regional facies Vertical ~$400K/well; 20 bbl/d Lloyd Channel facies HZ ~$800K/well; 50 bbl/d 2010: Drilled 6 wells Booked 37.4 Mbbl/well (avg. 20 Bbl/d) 2011: Q1 2 horizontals Q2 - Q4 26 vertical and deviated wells 2012: Expanded development Evaluating waterflood and other enhanced recovery Viking Kinsella Area Development Vertical ~$400K/well; 20 bbl/d 2010: Drilled 3 wells (1.5 net) Booked 27.1 Mbbl/well (avg. 15 Bbl/d gross) 2011: 6-10 infill locations drill ready Growing low-risk heavy oil drilling inventory in excess of 80 drill-ready ready locations 8
Resource Projects Deep Basin Liquids Rich Gas ROSEVEAR Edson Deep Cut Plant 375 MMcf/d capacity Edson Shallow Cut Gas Plant (30% WI) 30 MMcf/d capacity EDSON South Rosevear Shallow Cut Gas Plant (15% WI) 75 MMcf/d capacity 16-10 Compressor (100% WI) 30 MMcf/d capacity Pipeline connecting Carrot Creek and Edson CARROT CREEK Current Production (excluding Cardium Oil) Total West Central 7,500 boe/d 75/25 gas to NGLs split Q1 D&C Activity 3.5 net Wilrich wells 1.0 net vertical well Multi-Zone Area Targeting Viking, Bluesky, Wilrich, Lower Mannville, Fernie Sand & Rock Creek Liquids-Rich Gas 20-40 bbls/mmcf NGL s Extensive facility network Interest in 3 gas processing facilities Excess third party capacity Extensive prospect inventory 40 Multi-zone vertical drills Average depth = 2,450m ~$1.6 MM D C & E Risked IP 800 Mcf/d Risked EUR 0.7 Bcfe Perpetual Lands Perpetual WI Facilities Perpetual Pipeline Conoco-Philips Pipeline Alliance Pipeline Other Facilities Other Pipelines Rock Creek HZ loc Notikewin HZ loc Wilrich HZ loc Wolf South Deep Cut Plant 66 MMcf/d capacity Pipeline to Wolf Plant WEST PEMBINA R10 R9 R8W5 PEMBINA Pembina Oil Battery (78% WI) 1,200 BOE/d capacity 6 mi 20 horizontal locations (excluding Wilrich) ~$3.5 MM D C & E Risked IP 2 3 MMcf/d Risked EUR 1.6-2.5 Bcfe 37 Wilrich horizontal locations ~$5 MM D C & E Risked IP 4 MMcf/d Risked EUR 3 Bf Bcfe 30 Recompletion candidates Establishing operational excellence in vertical and horizontal development 9
Resource Projects - Edson Wilrich Pipeline to Edson Plant High pressure pipeline to Rosevear Plant (15% WI) 75 MMcf/d gross capacity 16-10 Compressor 30 MMcf/d Wilrich Update IPs 3.5-5.0 MMcf/d; 40 bbl/mmcf of NGLs (50% condensate) All wells drilled to date on production Current Wilrich production 23 MMcfe/d (net sales) 2 additional Hz wells planned for Q3 2011 16-10 compressor - Reviewing expansion to 50 MMcf/d 2010 Drilled Locations 2011 Drilled Locations Perpetual Wilrich Rights Other Perpetual Lands Pipeline to Wolf deep-cut plant Wilrich play now proved up with 7 wells Commercial development phase will drill to fill infrastructure 10
Wilrich Value Potential Economics per Drilling Location Assumptions Capital (D,C &T) $49MM $4.9 Pricing $4/Mcf; $75/bbl WTI = $53.20/bbl NGLs ($4/Mcf; $95/bbl WTI=$66.30/bbl NGLs) NPV @ 10 % $2.7 MM BT ($3.5 MM BT) (excluding drilling credits) Operating Costs Well Depth $6.45/BOE 3,900 M HZ; 2,400 TVD ROR 39% BT (50% BT) Type Curve IP 3.5 MMcf/d, One year exit rate 1.85 MMcf/d 36 bbls/mmcf NGL s/condensate F&D Capital Efficiency $10.70/ BOE <$12,000 BOE/d Flare while drilling 13-5 Wilrich HZ Reserves Royalties Risk 3 Bcfe per well 5% new well royalty rate for 500 MMscf; no drilling credits included Unrisked Preparing to Frac 13-5 Wilrich HZ Scope 44 gross (36.9 net) inventory locations
Resource Projects Pembina Cardium NOTE: Only Cardium producing wells shown Carrot Creek Focused Development: 61 Gross (36 Net) Sections of Cardium Rights CARROT CREEK Q1 2011 Program: Section 16-52-13W5 development 4 Gross (3.0 net) HZ wells EDSON PEMBINA Perpetual Cardium Lands Producing Cardium Wells Perpetual Cardium HZ Location Drilled Perpetual Vertical Well Location Cardium HZ Locations/License 6 mi 12
Resource Projects Carrot Creek Cardium Vero Q1 2011 Capital Section 16-52-13W5 13W5 development 3 operated Hz wells drilled and completed; production start-up late March 1non-op op Hz well; completion pending 43 (20.6 net) A Locations ~ 173 mboe/well 45 (30.2 net) B Locations ~ 150 mboe/well 48 (34.4 net) C Locations <50 mboe/well Drilled HZ Wells Vermillion CNRL Vero Bonterra Vermillion Perpetual Cardium Other Perpetual Lands 13
Carrot Creek Cardium Value Potential Capital (D,C & T) NPV @ 10 % Economics per Drilling Location $2.9 MM (multi-well program estimate) $3.1 MM BT ($4.6 MM) $2.1 MM AT ($3.2 MM) ROR 74% BT (128%) 49% AT (80%) Oil and Gas Price Operating Costs Well Depth A Type Curve Reserves Assumptions $75/bbl; $4/Mcf ($95/bbl; $4/Mcf) $13.00/BOE 3,050 m HZ; 1,750 TVD IP 150 bbls/d, 1yr Di 75%, 2yr Di 30%, 3 yr Di 25% 173,000 boe F&D $16.50/BOE Royalties 5% new well royalty rate for 70,000 bbls or 30 months; no drilling credits included Capital Efficiency $23,540 BOE/d Risk Unrisked 5-15 Battery Pumpjack at 4-16 Scope 88 Gross (51 net) locations at Carrot Creek 14
Resource Projects Elmworth Montney Liquids Rich Gas 78 Gross Sections of Montney Exposure 3 well earning commitment by Tourmaline fulfilled 50/50 Joint Venture with Tourmaline Reserves and Contingent Resource 32 Bcfe P+P reserves booked (7 sections) 145 Bcfe best estimate contingent resource (Assuming 35% recovery & 20 bbl/mmcf NGLs 34 gross (17 net) sections not yet evaluated (SW Block) Competitor i activity i i in i past 18 months h 9 HZ and 4 Vertical wells on production 8 addt l HZ wells rig released 4 new HZ wells licensed IP (1 month) of offset HZ wells 3 to 6 MMcf/d Viability of Play Confirmed Positive Thus Far 3 Perpetual-interest wells tested up to 7.5 MMcf/d/well Recombined free liquids and NGLs ~ 20 bbl/mmcf condensate plus 25 to 45 bbl/mmcf NGLs (processing dependent) Perpetual/Tourmaline Locations Montney Producers Perpetual Lands HZ Locations >1 TCF original g gas in p g place (gross) (g ) Resource p potential established Working g towards area development p plan p 15
Resource Projects Bitumen/Heavy Oil Perpetual OS Leases Primary Projects SAGD Projects Fireflood Projects CSS Projects Electric Heaters Oil Pipelines 521 net sections (333,000 net acres) of oil sand leases 7 unique project areas Various formation targets and ultimate recovery methods Bitumen in place volumetric estimate of > 5.6 billion bbls 2010 Activity Drilled oil sands evaluation well at Panny in Q1 2010 Drilled oil well at Marten Hills Q1 2010; 2 wells on cold production for evaluation 2011 Activity Testing 4 project areas - South Liege, Hoole, Panny and Clyde 9 verticals; 1 Hz 16 16
Viking / Colorado Tight Shallow Gas Vast Play Fairway Booked Reserves 6 Bcf P+P Producing 15 Bcf P+P Developed Non-Producing 111 Bcf P+P Undeveloped 837 drills in future development capital Average 138 MMcf/well gross Prospect Inventory 1,548 unrisked addt l possible locations catalogued Average 111 MMcf/new drill 2010 Initiated Technical study 3 vertical drills coring 200m each of Colorado/ Viking interval for detailed geological, geomechanical and geochemical analysis Q1-Q3 2011 Detailed core analysis and production inflow and fracture modeling Q4 2011 Multi-well pilot plan for Colorado Group, incorporating detailed core analysis and fracture and inflow modeling, to be determined Results of analysis will determine if pilot consists of new drills, recompleting existing wellbores or combination 17 2012 Incorporate learnings from pilot into commercial trials and full scale execution
Warwick Gas Storage 40 Bcf storage reservoir 10 Bcf cushion gas in place 22 to 25 Bcf potential working gas capacity 1.5 cycle facility WGSI Storage Leases Warwick Glauconitic -Nisku A Pool 5-18 WGSI Leases Well Site Pad Compressor Facility Pipeline Horizontal Wells Q1 2011 Hz Well Q2-Q4 2011 Hz Wells 1 mi 4-18 2-19 3D Seismic 2010 Drilled 6 additional Hz injection wells Began injection on Test Cycle - May 2010 Constructed facility capable of > 200 MMcf/d withdrawal rate Total WGSI cost $68 million Q1 2011 Gas withdrawal commenced Jan 1, 2011 First Test Cycle withdrawal 7.8 Bcf 1 new HZ well drilled Q2-Q4 2011 Cycle 2 working gas set at 17 Bcf Up to 2 new HZ wells to further increase working gas capacity towards 22 to 25 Bcf theoretical target WGSI facility fully operational Cycle 2 working gas set at 17 Bcf Expect ~$1 MM funds flow per Bcf working gas capacity 18
Asset Base Repositioning Progress and Next Steps Timing to Establish Future Capital Game Changer Progress and Next Steps Requirements Edson Wilrich Pembina Cardium Elmworth Montney Bitumen/Heavy Oil Type curve established as expected Moved to development phase - Drill to Fill recently expanded infrastructure Pursue capture of additional inventory and potential expansion Found Carrot Creek sweet spot Establish Carrot Creek type curve Fine tune program capital costs Drill to grow light oil production if Carrot Creek type curve attractive Reserve and resource established Longer term production test to establish liquids and flow characteristics Etblih Establish area development plan West Block exploration plan Panny cold production test to establish if future cold production growth plan is viable or if technology pilot required for near-cold flow OV drilling programs at Liege, Hoole and Clyde to establish Q1 2012 program for contingent resource drilling Current plan established Ongoing Ongoing June 2011 May 2011 July 2011 November 2011 July 2011 May 2011 Viking/Colorado Warwick Gas Storage Continue fracture simulation work Pilot project if fracture technology solution established Commercial Trial if economically attractive Commercial Trial if economically attractive July 2012 Established cycle 2 working gas capacity at 17 Bcf 2 new drills to further increase working gas capacity Current plan established September 2011 July 2012 April 2011 and ongoing September 2011
2011 Capital Programs
Q1 2011 Capital Spending Warwick Gas Storage (WGSI), $4.3 Conventional Gas Activity, $2.9 Q1 2011 Capital : $53 MM Heavily weighted to oil and liquids-rich gas Drill, Complete and Tie-ins: $43.2 MM Cardium 4 gross (3.0 net) HZ wells Wilrich 2 gross (2.0 net) new wells 2 gross (1.5 net) existing well completions & tie-ins Elmworth Montney 1 completion and tie-in of 1 well (carried) Bitumen, $5.8 Bitumen 10 gross (10.0 0 net) evaluation (OV) wells Conventional Gas 2 gross (1.5 net) strategic wells Recompletions / Workovers, o $4.9 Maintenance Capital, $1.5 Land/Seismic, $1.6 Unconventional Viking/Colorado, $1.6 Heavy Oil, $2.7 Cardium Tight Oil, $10.8 Wilrich Liquids-Rich Gas, $16.7 Conventional Heavy Oil 2 gross (2.0 net) wells Warwick Gas Storage HZ Recompletions / Workovers: $4.9 MM 32 recompletions/workovers & tie ins Seismic and Land: $1.6 MM Unconventional Viking/Colorado: $1.6 MM Colorado/Viking geomechanical and geochemical work Colorado Detailed core and fracture simulation work Maintenance, Abandonment & Reclamation: $1.5 MM 28 gross abandonments Target Production Additions ~19 MMcfe/d (1 st 12 month average) Budget Capital Efficiency ~$16,000/flowing BOE/d >$36 million (68% of total spending) targeting oil and liquids rich gas projects 21
Q2- Q4 2011 Capital Budget Q2-Q4 2011 Capital Budget: $37 MM Heavily weighted to oil and liquids-rich gas Drill, Complete and Tie-ins: i $26.5 MM Bitumen, $0.2 Recompletions / Workovers, $8.1 Warwick Gas Storage (WGSI), $3.2 Conventional Gas Activity, $1.3 Wilrich Liquids-Rich Gas, $9.7 Wilrich 2 gross (2.0 net) HZ wells Heavy Oil 28 gross (28.0 net) Lloyd/Sparky wells Conventional Gas 3 gross (2.5 net) strategic wells Viking/Colorado - small scale pilot WGSI 2 gross (2.0 net) HZ wells New Ventures 1 gross tight oil exploration well Recompletions / Workovers: $8.1 MM 41 recompletions/workovers & tie ins Seismic and Land: $2.1 MM Maintenance Capital, $0.7 Maintenance, Abandonment & Reclamation: $0.7 MM Land/Seismic, $2.1 Misc. abandonments New Ventures, $0.4 Unconventional Viking/Colorado, $1.9 Heavy Oil, $9.8 Target Production Additions ~13.3 MMcfe/d (1 st 12 month average) Budget Capital Efficiency ~$17,800 /flowing BOE/d >$20 million (55% of total spending) targeting oil and liquids rich gas projects 22
2011 Full Year Capital Scenario Total Capital: $90 MM Game Changer Activity Objective 2011 Capex Cardium Wilrich Oil Sands Colorado/Viking Montney Drill 4 gross Cardium wells Drill 4 wells, complete and tie in 6 wells Drill 10 wells, shoot seismic Complete fracture simulation modelling Small scale pilot Test and tie in 3 wells Establish Carrot Creek type curve, add oil focused production and cash flow Grow liquids rich and cash flow production, confirm Wilrich type curve at Edson Evaluate oil sands potential, book contingent resource, establish cold production in Panny Indicative Play Specific F&D ($/Boe) 11 $16.50 26 $10.70 6 contingent resource Determine GIP and optimize completion techniques 4 TBD Partner earning wells, prove up well deliverability and production type curve 0 $9.30 New Ventures Participate in 1 exploratory well 0 $9.30 Total Resource 47 East Conventional Heavy Oil East Conventional Gas Drill 26 vertical Lloyd development wells; 1 Hz Lloyd channel well and 1 Hz Sparky development well, Lloyd downspacing oil development Establish flow characteristics of Lloyd channel and Sparky horizontal wells 13 $18.00 73 recompletions/workovers and dtie ins 13 $6.00 High ROR @ $4 gas 5 shallow gas drills 4 $12.00 33 reclamation and abandonments 1 6 facilities overhauls 1 -- Land and seismic 4 -- Total Conventional 36 Warwick Gas Storage Complete facility construction and drill 3 HZ wells Increase working gas capacity 7 Total 90 23
Balance Sheet
Balance Sheet Current Net Bank Debt : ~$90 million after Q1 capital program Borrowing base on credit facility: $250 million (confirmed to May 10, 2011) Senior Unsecured Notes: $150 million Convertible Debentures: $235 million Effectively represents long term debt with the maturities from 2012 to 2015 TSX Symbol Amount Outstanding Coupon Rate Conversion Price Maturity Date 10 Day Weighted Avg. Trading Price PMT.DB.C $ 74.9 million 6.50% $ 14.20 June 30, 2012 $ 102 PMT.DB.D $ 100.0 million 7.25% $ 7.50 January 31, 2015 $ 102 PMT.DB.E $ 60.0 0 million 7.00% $ 7.00 Dec. 31, 2015 $ 103 Total Net Debt: ~$475 million Gas Storage Financing Arrangement: $42 million equivalent Delivery obligation for 8 Bcf of cushion gas in Q1 2015 >65% of total net debt has term of 4 years or greater 25
Balance Sheet Debt Reduction Total debt reduced 24% since Q2 2007, including an additional 10% in 2010 26
Senior Unsecured Notes Financing Perpetual closed offering of $150MM Senior Unsecured Notes on March 15, 2011 Proceeds initially used to reduce bank debt Will be used to manage repayment of 6.50% debentures due June 2012 Provides significant flexibility and term to PMT s debt (>65% due after 2014) Not intended to expand overall leverage ($ millions) Dec 31, 2010 Pro Forma High Yield Current March 31, 2011E Bank Debt 214 67 90 Senior Notes - 150 150 Convertible Debentures 235 235 235 Provides time to: Total Debt 449 452 475 Enhance value of game changers and understand which assets are long term keepers in Perpetual s asset mix and which will be funders Manage through gas price cycle low with decisions focused on value not liquidity Transition asset base to higher oil and NGL commodity mix Term debt provides flexibility in challenging gas markets 27
Maximizing Shareholder Value
Commodity Diversification 2011 Funds Flow (92% Gas, 8% Oil; Test Cycle to 17 Bcf) Key Assumptions: WTI ($/bbl) AECO($/GJ) 3.50 4.50 5.00 5.50 6.50 70 72 122 145 169 216 80 81 128 151 175 222 90 87 134 157 181 228 100 93 140 164 187 234 110 99 146 170 193 240 Note: Assumes 50 Bcf (137 MMcf/d) of gas and 750 Mbbls (2,000 bbls/d) of oil production (92%: 8%). 2012 Funds Flow (88% gas, 12% oil; 20 Bcf Cycle) AECO($/GJ) 3.50 4.50 5.00 5.50 6.50 70 92 137 160 183 228 80 101 146 169 191 236 WTI ($/bbl) 90 109 155 177 200 245 100 118 163 186 208 254 110 127 172 195 217 262 Note: Assumes 47 Bcf (129 MMcf/d) of gas and 1.0 MMbbls (2,740 bbls/d) of oil production (88% : 12%). Production: 148 MMcfe/d $90 million capital program with $3MM/MMcf production addition costs offsetting 20% base decline Current Forward Strip (April 1, 2011): ($/GJ AECO; $/bbl WTI) 2011 $3.65; $103.00 2012 $4.00; $106.50 2013 $4.40; 40 $103.50 Gas Storage Cash Flow: 2011 $14 MM (Ramp up from 7.8 Bcf Test Cycle to 17 Bcf working gg gas) 2012 $20 MM (20 Bcf working gas) 2013 $22 MM (22 Bcf working gas) 2013 Funds Flow (80% gas, 20% oil; 20 Bcf Cycle) AECO($/GJ) 3.50 4.50 5.00 5.50 6.50 WTI 70 120 161 182 202 243 80 ($/bbl) 135 176 196 217 258 90 149 190 211 231 272 Free cash flow over and above current $53 million dividend and $90 million capital program Current forward strip for commodity prices 100 163 205 225 246 287 110 178 219 239 260 301 Note: Assumes 42 Bcf (115 MMcf/d) of gas production and 1.8 MMbbls (4,900 bbls/d) of oil production (80% : 20%).
Reserve Report Opportunity Inventory -Unrisked Current Recorded Prospect Inventory 2010 Year End P + P Reserves = 487.7 Bcfe Unrisked Additional Reserve Potential = 1,367 Bcfe Gas Over Bitumen Proved + Probable UnDeveloped + UnConventional Tight Gas Resource Plays (Rock Creek Notikewin) Conventional Shallow Gas Drills Conventional Recompletions UnConventional Tight Gas Resource Plays (Montney) UnConventional Tight Gas Resource Plays (Wilrich) Proved + Probable Developed Gas Storage + Option Value NE AB Bitumen Tight Oil and Gas Exploration GOB Technical Solutions TriOil Exploration Bitumen In-Situ UnConventional Tight Shallow Gas Resource Plays (Viking, Colorado) Unconventional Tight Oil (Cardium) East Central Heavy Oil As technical understanding advances, risk assessment adjusts and risk-discounted potential grows 30
Sum of the Parts Risked Value Potential Conventional Projects Asset Measure Valuation Range ($MM) Reserve Report PV10% $480 Prospect Inventory 1,485 net locations and recompletions 175-270 Resource Projects Reserve Report PV10% $145 Deep Basin 57 net locations 30 40 Wilrich 36 net locations 65 160 Cardium 69 net locations 20 75 Montney 111 net locations 80 325 Viking / Colorado 822 net locations 60 90 Bitumen 120 MMbbls contingent resource 20-40 Gas Storage 17 22 Bcf working gas @ $10 MM /Bcf $170 $220 Investment in TriOil 1.3 MM shares $5 - $10 TOTAL $1, 250 $1,855 Net Total Debt March 31 $(475) NET TOTAL VALUATION RANGE $775 $1,380 Per Share (148.3 MM shares) $5.23 - $9.31 Source: Company Estimates Significant value from multiple assets provides Perpetual with future optionality 31
Investment Thesis Asset base repositioning to add high impact, resource-style, liquids-focused opportunities successful Edson Wilrich and Carrot Creek Cardium entering development phase Elmworth Montney resource identified and scoping development scenarios Q1 2011 capital program will further define potential for: Bitumen contingent resource at Liege, Hoole and Clyde Panny cold flow potential Horizontal Sparky and Lloyd channel conventional heavy oil development Ongoing results will dictate future capital spending requirements to optimize shareholder value Diversified cash flow from gas storage asset On pace to grow cash flow to $15 - $20 million per year Sum-of-the parts analysis at current gas prices, based on reserves, risked valuation of resource plays and gas storage asset, defines an attractive return on investment Evolving commodity mix provides increasing cash flow in current high oil price environment Tremendous leverage to a recovery in gas prices Every $0.50 per Mcf = $25 million of cash flow 65% of debt will have term beyond 2014 providing flexibility to manage through low in gas price cycle Multiple levers available to manage balance sheet to optimize value Focused on Maximizing Shareholder Value 32
3200, 605 5 Avenue SW Calgary, Alberta CANADA T2P 3H5 800.811.5522 TOLL FREE 403.269.4400 PHONE 403.269.4444 FAX info@perpetualenergyinc.com EMAIL www.perpetualenergyinc.com WEB FOR ADDITIONAL INFORMATION: Susan L. Riddell Rose President & CEO Cameron R. Sebastian Vice President, Finance & CFO
Appendices CIBC 2011 Energy & Infrastructure t Conference
2010 Q4 and Annual Results
2010 Operating Results Production Daily Natural Gas (MMcf/d) Daily Oil and NGL (Bbl/d) Natural Gas Pricing ($/Mcf) Oil and NGL Pricing ($/Bbl) Unit Operating Costs ($/Mcfe) Operating Netback ($/Mcfe) Wells Drilled (gross/net) Three Months Ended December 31 Year Ended December 31 2010 2009 % Change 2010 2009 % Change 135.9 139.8 (3) 145.1 153.4 (5) 1,535 1,014 51 1,245 721 73 Before hedging 3.87 3.94 (2) 4.17 4.12 1 After hedging 7.83 5.53 42 7.10 7.09-75.88 67.33 13 68.29 61.91 10 1.56 1.41 11 1.64 1.83 (13) 6.33 4.03 57 5.24 4.94 6 7/4.44 9/8.5 (22)/(48) 70/63.9 52/42.22 35/51 36
2010 Financial Results Three Months Ended Year Ended December 31 December 31 ($ Millions except per Common Share amounts) 2010 2009 % Change 2010 2009 % Change Revenue 111.2 78.9 41 417.1 418.3 - Funds Flow 71.0 39.4 79 237.2 231.3 3 Per Common Share 0.48 0.32 50 1.69 1.96 (14) Net Earnings (Loss) (20.0) 0) (11.3) 76 (28.5) 14.44 (298) Per Common Share (0.13) (0.09) 44 (0.20) 0.12 (266) Exploration & Development 49.3 10.1 388 173.1 68.2 153 Acquisitions, net of dispositions (34.3) (10.0) 243 50.7 103.9 (49) Bank Debt 215 271 (21) 215 271 (21) Total Debt (incl. debentures) 449 501 (10) 449 501 (10) Dividends 16.3 18.8 (13) 78.6 75.8 4 Per Common Share 011 0.11 015 0.15 (27) 056 0.56 064 0.64 (13) 37
2010 Annual Financial Highlights g Funds flow increased 3% to $237 million in 2010 from $231 million in 2009 Net bank debt decreased 21% from $271 million at December 31, 2009 to $215 million at December 31, 2010 Total net debt decreased 10% at year-end to $449 million from $501 million at year-end 2009 Operating costs decreased 13% to $91 million ($1.64 per Mcfe) in 2010 as compared to $105 million ($1.83 per Mcfe) in 2009 38
2010 Production Highlights g Actual and deemed production was flat year over year at 177.4 MMcfe/d vs 177.6 MMcfe/d in 2009 Production decreased 3% to 152 MMcfe/d as a result of asset dispositions, the full year effect of the Legend shut-in late in 2009 and natural production declines, partially offset by the Edson acquisition and successful drilling activities Successful Pembina Cardium, Edson Wilrich and Mannville Lloyd drilling programs in the second half of 2010, increased oil and NGL production 73% to 1,245 bbl/d from 721 bbl/d in 2009; Currently 1,600 bbl/d 2009 (177.6 MMcfe/d) 2010 (177.4 MMcfe/d) 19.9, 11% 4.3, 3% 24.8, 7.5, 4% 14% 153.4, 86% 145.1, 82% Natural Gas Gas over Bitumen Deemed Oil and NGL s 39 Increasing exposure to oil and NGLs with liquids-focused capital programs
2010 Capital Activities Spent $115.2 million on exploration and development compared to $57.4 million in 2009 Drilled 70 gross wells (63.9 net) vs. 52 gross (42.2 net) in 2009 with a 98% net success rate. Drilling activity included 48 gross (44.3 net) gas wells and 14 gross (11.6 net) oil wells and 6 gross (6.0 net) gas storage wells Acquisition spending, net of disposition proceeds was $50.7 million vs $103.9 million in 2009 Dispositions of non-core assets increased to $91 million from $26.6 million in 2009 and included the disposition of shut-in GOB assets for $40 million with retention of the related financial solution royalty reductions 2010 capital to develop Warwick gas storage reservoir and construct facility totaled $57.6 million Total net capital expenditures in 2010 were $224.1 million vs $172.7 million in 2009 40
Capital Expenditures Capital Expenditures As asset base transition takes shape increasingly more capital to liquids rich gas and oil resource plays 41
2010 Acquisitions and Dispositions Reconciliation 2010 Acquisitions 2010 Dispositions (1) Net Properties Edson Wostock/Ukalta Warwick Cold Lake Legend Shut-in GOB Liege Shut-in GOB Leismer Shut-in GOB Grande Prairie East Cochrane Viking Kinsella Portion of Calling Lake North Edson P+P Reserves (Bcfe) (3) 43.33 53.1 (9.8) Actual/Deemed Production (2) (MMcfe/d) 17.3 12.2/9.7 5.1/15.7 Undeveloped Land (net acres) 79,887 54,690 25,197 Capital ($ millions) ($141.9) $91.3 ($50.6) 1) Dispositions included 34.2 Bcf (5.7 MMboe) of probable shut-in gas over bitumen reserves where funds flow from the gas over bitumen financial solution royalty credit was retained by Perpetual 2) Production at time of acquisition iii or disposition; ii deemed dproduction for gas over bitumen financial i solution royalty reduction expected to increase after ERCB decision 3) Based on Year End 2010 Reserve report 42
2010 Year End Reserves Added 72.1 Bcfe of proved and probable reserves, replacing 129% of production (111% total proved) After dispositions of 53.1 Bcfe and production of 55.7 Bcfe, P+P reserves increased 3% to 488 Bcfe and proved reserves increased 2% to 250.4 Bcfe Excluding downward d revisions i related solely l to changes in natural gas pricing i at year-end 2010 of 22.3 Bcfe, reserves grew 8% year over year from 471.6 Bcfe (78.6 MMboe) to 510.0 Bcfe (85.0 MMboe), offsetting production of 55.9 Bcfe (9.3 MMboe) and net dispositions of 9.8 Bcfe (1.6 MMboe) Reserve to production ratio ( reserve life index or RLI ) of 8.7 years P+P (4.9 years proved) F&D Including changes in future development capital ( FDC ), Perpetual realized P+P F&D of $1.69 per Mcfe ($10.14 per BOE) P+P FD&A costs, including changes in FDC, were $2.16 per Mcfe ($12.96 per BOE) (1) 2010 FD&A costs 2.16/Mcfe (1) 43 (1) Excluding GOB disposition proceeds and reserves as funds flow retained
2010 Year End Reserves Bcfe 2010 2009 % Change Proved Producing 201 203 (1) Proved Non-Producing 22 8 175 Proved Undeveloped 27 33 (18) Total Proved 250 244 2 Probable Producing 68 67 1 Total Probable 169 161 5 Total Proved and Probable 488 472 3 Discoveries and extensions +77 Bcfe Technical revisions +28 Bcfe Production -56 Bcfe Net Dispositions -9 Bcfe Reserve reductions due to economic factors (gas price) -22 Bcfe 3% reserves growth in 2010 44
Elmworth Montney Reserves and Contingent Resource McDaniel recognized >1.0 Tcf OGIP on 42 gross sections of Perpetual s Elmworth Montney acreage 14.5 Bcfe (2.4 MMboe) of proved and 32.1 Bcfe (5.3 MMboe) of P+P reserves booked at year-end 2010. Reserve assignments on 7 of 78 gross sections of PMT-interest land Excluding the portion with booked reserves, the best estimate recoverable contingent resource is estimated at 145.0 Bcfe (24.22 MMboe), assuming a 35% recovery factor and 20 to 25 bbls/mmcf NGLs 34 gross (17 net) additional sections have not yet been evaluated through drilling in the Montney and dtherefore have no contingent tresource or reserves assigned as yet OGIP>1 Tcf;32Bcfe reserves booked; 145 Bcfe additional contingent resource recognized 45
2010 Year end Reserves Reserves By Category (487.7 Bcfe - Company Interest) Gas over Bitumen Proved Undeveloped, d 27.4, 6% Shut-in, 27.2, 6% Proved Developed Non-producing, 21.6, 4% Probable Undeveloped, 108.1, 22% Proved Developed Producing, 201.4, 42% Probable Developed Non-producing, 34.4, 7% Probable Developed Producing 64.8, 13% 55% of reserves are proved and probable developed producing 46
Reserve Characteristics Proved Reserves by Play (in Bcfe,% of total) 8, 3% 15, 6% 2, 1% 11, 4% 48, 19% 167, 67% Conventional West Central Viking GOB Cardium Wilrich Montney 1. Independent reserve evaluator McDaniel & Associates Ltd. 67% of proved reserves from Conventional projects 47
Reserve Characteristics Proved and Probable Reserves by Play (in Bcfe, % of total) 16, 3% 32, 7% 27, 6% 3, 1% 233, 47% 105, 21% 71, 15% Conventional West Central Viking GOB Cardium Wilrich Montney 52% of proved and probable reserves from Resource projects 1. Independent reserve evaluator McDaniel & Associates Ltd. 48
Natural Gas Markets
Natural Gas Market Highlights g Producer sentiment shifting Diminished contango in the forward curve reduces desire to drill and hedge Rigs and capital are slowly being diverted to oil and liquids plays Cold winter has significantly eroded storage surplus Exit withdrawal season @ ~ 1.6 Tcf vs 1.9-2.2 Tcf previous market expectation Difference is ~ 2.5 Bcf/d of demand for injection this summer Cash prices (including AECO) have been much stronger than futures Strong coal prices are providing a floor for gas prices Estimate coal-gas switching to create ~ 1.25 Bcf/d of incremental demand Dramatic migration of services from gas to oil/liquids plays Service availability and inflation is becoming challenging for tight gas drilling Financial bears have been holding the market low Long crude - short natural gas offset trades have resulted in record shorts Reduced volatility will begin to fatigue the shorts Crystallized hedge book value in November 2010 with view at bottom of price cycle Fundamentals strengthening 50
US Natural Gas Storage Source: Credit Suisse, April 1, 2011 Cold winter = gas storage erosion 51
US Coal Demand Rising coal costs create a backstop for natural gas prices 52
US Gas Rig Count Source: Smith International; Credit Suisse April 1, 2011 Horizontal rig count down 3% quarter over quarter 53