First Energy Capital EnergyGrowth Conference November 16, 2010

Transcription

1 First Energy Capital EnergyGrowth Conference 2010 November 16, 2010 Forward-Looking Statements Certain information regarding PERPETUAL ENERGY in this presentation may constitute forward-looking statements under applicable securities laws. Forward-looking statements may be identified by words like forecast, estimated, expected or similar expressions. These forward-looking statements are based on certain assumptions that involve a number of risks and uncertainties and are not guarantees of future performance. Risks and uncertainties may include, without limitation, risks associated with gas exploration, development, exploitation, production, marketing and transportation, changes to the proposed royalty regime prior to implementation and thereafter, loss of markets, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other producers, inability to retain drilling rigs and other services, capital expenditure costs, including drilling, completion and facilities costs, unexpected decline rates in wells, delays in projects and/or operations resulting from surface conditions, wells not performing as expected, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources. These forward-looking statements are based on certain assumptions that involve a number of risks and uncertainties and are not guarantees of future performance. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements as a result of changes in Perpetual s plans, changes in commodity prices, regulatory changes, general economic, market and business conditions as well as production, development and operating performance and other risks associated with oil and gas operations. Furthermore, the forward-looking statements contained in this presentation are made as at the date of this presentation and Perpetual does not undertake any obligation to update publicly or to revise any of the forwardlooking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws. 1

2 Market profile Common shares outstanding million Management ownership 21% Share price (5 day weighted average) $ Current dividend (monthly) $ 0.03 Current annualized yield 8% Average daily trading volume 477,914 Market capitalization Convertible debentures Net bank debt Enterprise value $ 635 million $ 235 million $ 225 million $ 1.1 billion Corporate conversion from Paramount Energy Trust completed July 1, 2010 Entrepreneurial Approach to Value Creation BASE ASSETS GAME CHANGERS OPTION VALUE Sustainable Cash Flow Generators Legacy Conventional Shallow Gas in Northeast & East Central Alberta Deep Basin Liquids-rich Tight Gas West Central Alberta + High Impact Resource Exposure to Emerging Plays Technologies Pembina Cardium Tight Oil Edson Liquids-rich Wilrich Gas Elmworth Montney Gas Viking and Colorado Shale Tight Shallow Gas Eastern Alberta Heavy Oil + GOB Technical Solutions NE Alberta Bitumen Tight Oil & Gas Exploration CO 2 Seq n & Storage Mannville CBM + + Warwick Gas Storage TriOil Resources (4%) = Shareholder VALUE 2

3 Growth Plus Income Strategy DIVIDENDS: Targeting Sustainable Yield BASE CASH FLOW GENERATORS: Targeting Sustainable Production and Cash Flow HIGH IMPACT RESOURCE PLAYS : Targeting Growth And Cash Flow Diversification SYNERGISTIC ENTREPRENEURIAL IDEAS: Targeting Value And Cash Flow Diversification Assets and Operations Stability + High Impact New Ventures Natural Gas Focused Base Asset Optimization: Conventional Shallow Gas (85%) Deep Basin Liquids-Rich Tight Gas Resource Plays (15%) Oil & Liquids-Focused High Impact Resource Style Growth: Elmworth Montney Pembina Cardium Tight Oil Edson Wilrich Liquids-rich gas Synergistic High Impact Value Propositions: Eastern Alberta Heavy Oil and Bitumen Viking and Colorado Shale Tight Shallow Gas Warwick Gas Storage Current Daily Production - 96% Natural Gas Gas over Bitumen Deemed Production (1) P+P Reserves (2) Reserve to Production Ratio (P+P) (RLI) 147 MMcfe/d (~24,500 BOE/d) 25.1 MMcf/d Bcfe 8.9 Years (1) Includes 10.5 MMcf/d interim shut-in order issued by ERCB effective October 31, 2009 (2) As evaluated by McDaniel and Associates including acquisitions and net of dispositions to September 30, 2010 Trend to Cash Flow Diversification 3

4 Base Assets Eastern Alberta Cash Flow Generators Cretaceous and Devonian sweet shallow gas Multiple stacked zones and play types Belly River Viking 1,200 uphole recompletions awaiting depletion of producing zones Low cost production and reserves adds (<$10,000/flowing BOE; <$1/Mcf) Typically ~150 recompletions per year 800+ new drill prospects in various stages of Grand Rapids technical delineation Seismic definition and step out of infrastructure drive prospects to drill ready Lower Mannville 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 Pre Cretaceous Typically ~ 55 new drills per year Unconformity Average well $0.4 MM D C & E Risked IP 300 Mcf/d; EUR O.3 Bcf (<$20,000/flowing BOE; <$1.50/Mcf) 85% of production / ~ 20% of PET value potential 4

5 West Central Alberta Deep Basin Tight Gas ROSEVEAR Edson Gas Plant (30% WI) 30 MMcf/d Capacity Perpetual Lands Edson Acquisition Perpetual WI Facilities Perpetual Pipelines Other Facilities Other Pipelines Rock Creek HZ loc Notikewin HZ loc Wilrich HZ loc EDSON Multi-Zone Area Targeting Viking, Bluesky, Wilrich, Lower Mannville, Fernie Sand & Rock Creek South Rosevear Liquids-Rich Gas Gas Plant (15% WI) bbls/mmcf NGL s 75 MMcf/d capacity Extensive facility network Interest in 3 facilities Excess third party capacity Tight Gas Prospect Inventory 40 Multi-zone vertical drills Average Depth = 2,450m ~ $1.6 MM D C & E Risked IP 800 Mcf/d CARROT CREEK Risked EUR 0.7 Bcfe 60 Horizontal locations ~$3.5 MM D C & E Risked IP 2,000 Mcf/d Risked EUR 1.6 Bcfe 30 Recompletion candidates Carrot Creek/Pembina 1,730 boe/d Edson 1,690 boe/d Total West Central 3,420 boe/d Pembina Oil Battery (78% WI) 1,200 BOE/d capacity WEST PEMBINA PEMBINA 6 mi Game Changers The De-Risking Phase 5

6 Pembina Cardium Tight Oil HZ Development EDSON CARROT CREEK Carrot Creek: 61 Gross (36 Net) Sections of Cardium Rights Edson: 37 Gross (31 Net) Sections under Farm-In Farm-In Terms: 100% to earn 50% Interest in 4 Sections 2 HZ Commitment Wells with Rolling Option to Earn Additional Lands 2010 Program: 3 Gross (1.9 Net) HZ at Carrot Creek 1 Gross (1 Net) Vertical Exploration Well 2 Gross (1.2 Net) HZ in Edson Perpetual Cardium Lands Edson Acquisition PEMBINA Results: Average 30 day rate ~ 175 BOE/d (First 4 wells) Top decile producer at 4-16 (315 BOE/d - 45 days) Fifth well undergoing completion operations Meeting type curve expectations Producing Cardium Wells Perpetual Cardium HZ 2010 Locations Perpetual Vertical Well Location Competitor Cardium HZ Locations 6 mi NOTE: Only Cardium producing wells shown Carrot Creek Cardium Development R14 R13 R12W5 VRO T BOE/d 3-9 T Development Potential (Gross/Net) 41/19.9 A Locations 173 mboe/well 47/30.8 B Locations 150 mboe/well 48/34.4 C Locations? mboe/well Vermilion CNQ Development Scenario at 4 wells/section VRO Bonterra Perpetual Cardium Perpetual Lands 6

7 Carrot Creek/Edson Cardium Value Potential Economics per Drilling Location Capital (D,C & T) $2.9 MM (multi-well program estimate) 10 % $3.1 MM BT $2.1 MM AT ROR 74% BT 49% AT F&D $16.50/BOE Capital Efficiency $23,540 BOE/d Carrot Creek Scope 94 gross (52 net) unrisked locations Oil / Gas Pricing Operating Costs Well Depth Assumptions $75/bbl; $5/Mcf $13.00/BOE (BT) 3,050 m HZ; 1,750 TVD Type Curve IP 150 bbls/d, 1yr Di 75%, 2yr Di 30%, 3 yr Di 25% Royalties 5% New well royalty rate for 70,000 bbls/30 months; no drilling credits included Risk Unrisked Edson Farm-In 44 gross (19 net) unrisked locations 4, Before Tax Cash Flow, ($M) 3,000 2,000 1, , Avg Daily Production, (boe/d d) Capital ($M) Cumulative Btax Net CF NPV10 ($M) Average Annual Rate (boe/d) -2,000 Years from Spud -100 Wilrich R19 R17 R15 R13W5 T55 Marlboro Field Analogy T54 Competitor Activity IP s MMcf/d T53 Edson 13-5 HZ 4.25 MMcf/d IP 40 bbl/mmcf NGL s T52 Edson Carrot Creek Wilrich Re-Completions T51 Perpetual Wilrich Rights Perpetual Lands 7

8 Edson Wilrich Development R16 R15W5 To Rosevear Plant (15% WI) 90 MMcf/d gross capacity T Compressor Expansion 10 to 30 MMcf/d Perpetual Wilrich Rights Perpetual Lands 2010 Expanded CAPEX Program 4 Horizontal wells (4.0 net), 3 Recompletions (3.0 net) $5 million on Facilities Expansions ($3.5 million net) Vertical Recompletions IP ~400 Mcf/d 2011 Q1 CAPEX 3 Horizontal wells (2.5 net) Future Development Locations 33 gross (~30.5 net) W5 HZ IP >4.25 MMf/d On Prod Aug m3 water pits 13 5 Wilrich Frac Wilrich Production Profiles Analogous Wells W5 Production (m mcf/d) 1000 Type Well (unrisked) W W W5 Unrisked Type Well W W W Month 8

9 Economics per Drilling Location Capital (D,C & T) $4.9 MM 10 % $4.0 MM ($2.7 MM) BT ROR 56% (39%) BT F&D $10.70/ BOE (sales) Capital Efficiency <$12,000 BOE/d Scope Edson 41 gross (33.5 net) unrisked locations Pricing Operating Costs Well Depth Type Curve Royalties Risk Assumptions $5/Mcf ($4/Mcf); NGL s/condensate average price $53.2/bbl $6.45/BOE Post full plant expansion 3,900 M HZ; 2,400 TVD IP 3.5 MMcf/d, One year exit rate 1.85 MMcf/d 36 Bbls/MMcf NGL s/condensate 5% new well royalty rate for 500 MMscf; no drilling credits included Un-risked Flare while drilling 13 5 Wilrich HZ Elmworth Montney Tight Gas Exploration ELMWORTH Rights Held By Perpetual # Gross Sections ELMWORTH Upper Montney 14 HZ Wells Offsetting Perpetual Lands Perpetual/ Tourmaline Locations Grande Prairie Montney Doig Halfway Nikanassin Total Perpetual Activity 10 Parcels acquired 100% for $19 MM 19,904 ha Earning agreement in place for 50% Partner with Montney operating expertise Montney Penetration Montney Producer Proposed Montney HZ Location 6 mi KARR Lower Montney Turbidite 18 HZ Wells Offsetting Perpetual Lands 9

10 Elmworth Montney 78 Sections of Montney Exposure Acquired 100% WI in 2008 Gross Reserve Potential: 3 5 Bcf /Well Bcf+ (North Block preliminary development) Potential Location Inventory North and East Block only: 120+ gross wells Additional 38 gross sections of prospective acreage Competitor activity in past 18 months 4 HZ and 4 Vertical wells on production 6 addt l HZ wells rig released 4 new HZ wells licensed Viability of Play to be confirmed in well drilling commitment in 2010 by Tourmaline Oil with Montney operating expertise PEOC carried 100% on DC&E for the first 3 wells Partner to earn 50% working interest in all lands Perpetual/Tourmaline Locations Montney Penetrations Perpetual Lands HZ Locations Elmworth Montney T72 T70 R12 R10 R8 R6 R4W6 Grande Prairie Montney Resource Area Conoco Hz Encana Hz Rock Energy Hz NuVista Hz Daylight Hz Paramount Res. Hz Perpetual/Tourmaline T68 Unexplored Montney Potential Sweet Spot Sour Pipelines Montney Resource Area (10-30 Bcf/sec) Montney Sweet Spot ( Bcf/sec) Perpetual Lands T66 Sweet Spot 10

11 Elmworth Montney Value Potential Economics per Drilling Location Capital (D,C & T) $7.5 MM Gas Price 10 % $3.0 MM ROR 49% BT, 34% AT Operating Costs F&D $1.55/Mcfe ($9.30/BOE) Well Depth Capital Efficiency $4,600/Mcfe ($27,000/BOE) Sales Type Curve Deliverability Scope EUR North & East Block 41 gross sections (3 wells/section) NGL s/condensate Unrisked Potential % WI West Block Add tl 38 gross sections Royalties Unrisked Potential % WI Risk Assumptions $5/Mcf; Condensate $75/bbl; NGL $58.40/bbl $1.88/Mcf (post facility construction) 4,500 m HZ; 2,600 m TVD IP 5 MMcf/d to 1 MMcf/d in 12 mths, 18% Di after 12 mths 3.4 Bcf/well 35 bbls/mmcf NGL 30 bbls/mmcf Condensate 5% new well royalty rate for 500 MMscf; including drilling credits Un-risked Viking/Colorado Tight Shallow Gas 2010 Viking Drills 5 vertical, 2 HZ Vast Play Fairway Booked Reserves ~10 Bcf P+P Producing 15 Bcf P+P Developed Non-Producing 101 Bcf P+P Undeveloped 913 drills in future development capital Average 138 MMcf/well gross Prospect Inventory 1,210 unrisked addt l possible locations catalogued Average 111 MMcf/new drill 2010 Program 5 verticals, 2 Viking horizontals in Craigend Up to 20 recompletions for Viking for reserve conversions 3 vertical drills coring 200m of Colorado/Viking interval for detailed geological, geomechanical and geochemical analysis Q Program Detailed core analysis and fracture modeling Remainder 2011 Program Development drilling in Craigend for Viking Multi-well pilot for Colorado Group incorporating detailed core analysis and fracture modeling into drilling, stimulation and production pilot plan Potential 2012 Program Incorporate learnings from pilot into commercial trials and full scale execution 11

12 Heavy Oil/Bitumen Resource Exposure 521 net sections (327,000 net acres) of oil sand leases 7 unique project areas Various formation targets and ultimate recovery methods Bitumen in place estimate of > 5.6 billion bbls 2010 Activity Drilled oil sands evaluation well at Panny in Q Drilled oil well at Marten Hills Q1 2010; 2 wells on cold production for evaluation 2011 Potential Activity South Liege, Hoole, Panny and Clyde Perpetual OS Leases Primary Projects SAGD Projects Fireflood Projects CSS Projects Electric Heaters Oil Pipelines Birchwavy East Heavy Oil Program T56 Duvernay T54 R12 R10 R8W4 Mannville Lloyd Development OOIP = 34.6 MMstb in 3 pools Drilled 6 wells in 2010 Estimate 5% RF on primary at 2 wells per LSD 60 plus locations (1.7MMstb) Regional facies Vertical development Channel facies Horizontal development Evaluating Waterflood (add ~3MMstb) T52 T50 T48 Mannville 2011:20 40 wells Viking Kinsella 2011: 6 10 wells (50% WI) Viking Kinsella Sparky Development OOIP = 5.2 MMstb Drilled 3 wells in 2010 Estimate 10% RF on primary at 2 wells per LSD 6 10 remaining locations 50% partner with CNRL New Pool Evaluations and Exploration 2010: 1 recompletion 2011: 3 drills Mannville & Devonian Targets Oil Prospecting Utilizing in house data assets 12

13 Warwick Gas Storage Project Lamont Two Hills Edmonton Mundare Warwick Glauconitic - Nisku A Pool Vegreville NOVA Pipeline ATCO Pipeline Alliance Pipeline 6 miles Strategic location close to Nova and Alliance pipelines & ATCO distribution system Warwick Gas Storage Project R15W4 40 Bcf storage reservoir 10 Bcf of cushion gas in place 3 5 Bcf new cushion gas 22 to 25 Bcf of working gas 1.5 cycle facility WGSI Storage Leases R14W4 Project Viability Evaluation Phase: H $10.8 MM 3D Seismic First horizontal well (11-8) Withdrawal and injectivity test Delineation and Testing Phase: Q $9.4 MM 8 additional horizontal wells T53 Warwick Glauconitic -Nisku A Pool Full Scale Development: First Injection May 2010 Q2-Q $39 MM facility First Withdrawal November compressors; 3 Bcf cushion gas Year 1 Cycle 8-10 Bcf working gas; 105 MMcf/d withdrawal rate ~$8.5 MM forecast 2010 cash flow Year 2 Expansion: additional horizontal wells Year 2 Cycle Bcf working gas ~$12-20 MM forecast cash flow WGSI Leases Well Site Pad Compressor Facility (under construction) Pipeline Horizontal Wells Q HZ Drill 1 mi 3D Seismic Future Expansion: Up to 2 Bcf additional cushion gas Bcf working gas 200 MMcf/d max withdrawal ~$20-30 MM forecast cash flow/year Salt Cavern Development Potential 13

14 Warwick Gas Storage Facility Complete Compressor Bldg. Nova Meter Station South Pad Wells North Pad Wells Separators & Dehydrators C i l P Capital Programs Q Q

15 2010 Q4 Budget 2010 Original E&D Capital Budget: $81 MM 2010 Expanded E&D Capital Budget: $112 MM 2010 Warwick Gas Storage ( WGSI ) Budget: $52 MM Q4 Capex : E&D ~$35 MM WGSI~ $7 MM Drilling 3 HZ drills targeting liquids-rich Wilrich formation Complete final well in 5 well Cardium evaluation program Carried interest in 1 Elmworth drill Colorado Group 3 well coring program Heavy oil program complete and equip new drills D,C & T 1 well at Warwick for gas storage withdrawal Pipeline and Facilities Expansion of Edson compression facility from 10 MMcf/d to 30 MMcf/d Completion of Warwick Gas Storage facility Seismic and Land Q Capital Program Preliminary Preparation Costs Q Capital Budget Q Capital Budget: $48 MM Heavily weighted to oil and liquids-rich gas Maintenance Capital, $6.6 Recompletions/ Workovers, $7.6 Conventional Gas Activity, $3.5 Wilrich Liquids-Rich Gas, $13.0 Drill, Complete and Tie-ins: $33 MM Cardium 3 gross (1.8 Net) HZ wells Wilrich 3 gross (3.0 Net) wells Elmworth Montney Carried interest in last of 3 earning wells Heavy Oil/Bitumen 10 gross (10.0 Net) evaluation wells Conventional 4 gross (4.0 Net) strategic wells Recompletions / Workovers: $7 MM 50 recompletions/workovers & tie ins Seismic and Land: $4 MM Heavy Oil/Bitumen, $5.8 Colorado/Viking geomechanical and geochemical work Cardium Tight Oil, $10.7 Maintenance, Abandonment & Reclamation: $4 MM 31 gross abandonments Target Production Additions ~12.2 MMcfe/d (1st 12 month average) Budget Capital Efficiency ~$20,000/flowing BOE/d >$30 MM Targeting Oil and Liquids Rich Gas Projects 15

16 Outlook Price Risk Management Strategy Protect the level of the Trust s monthly distributions and manage the balance sheet Enhance or protect the economics of an acquisition as prices vary from those forecast Enhance or protect capital program economics Capitalize on perceived market anomalies Current Hedge Position (November 8, 2010) Term Volumes at AECO (GJ/day) Price ($/GJ) AECO/NYMEX Futures Price ($/GJ) (2) % of 2010E Production (3) December 2010 March ,000 $7.75 $3.59 5% (1) Additional call option contracts outstanding are as presented in management s discussion and analysis ( MD&A ) (2) Futures price reflects forward market prices as at November 5, 2010 (3) Calculated using production capability of 192,000 GJ/d, including actual and gas over bitumen deemed projected production Recent Hedge Book Crystallization Bought back forward hedge positions in Q for proceeds of $37 MM View that there is more upside than downside from current prices Current mark-to-market value of hedge book $6.2 MM Realized Gains of $154 Million To-date in

17 Bullish Gas Market Factors Fundamental factors starting to show signs that natural gas market may be in store for a turn to the upside: 1. Producers Starting to Show Some Restraint 2. Dry Gas Rig Count Falling 3. Drilling to Hold Haynesville Gas Leases is Nearing an End 4. Hedge Roll Offs 5. Few Plays Break-even at 2011 Curve of ~$4/MMBtu 6. Diminishing Contango in the Gas Curve Presents Less Desire to Drill 7. Ongoing Coal-to-Gas Switching Among US Utilities 8. Record Short Positions in the Market 9. Industrial Demand Strengthening 10. Winter weather demand upon us forecasts similar to 2010 Base Declines will Become Transparent when Capital Spending Slows Bullish Gas Market Factors Source: Commodity Weather Group Many Forecasters Calling for Cold Early Winter in Key Consuming Regions 17

18 Industrial Demand (year-over-year Bcf/d change) Industrial Demand is in Recovery Balance Sheet Current net bank debt: ~$225 million Borrowing base on credit facility: $346 million (November 30 redetermination pending) 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% $ June 30, 2012 $ 101 PMT.DB.D $ million 7.25% $ 7.50 January 31, 2015 $ 104 PMT.DB.E $ 60.0 million 7.00% $ 7.00 Dec. 31, 2015 $ 102 Gas Storage Financing Arrangement: $31.8 MM at Sept 30 th ; $42 MM upon facility completion Delivery obligation for 8 Bcf of cushion gas rolled to Q Premium DRIP Plan Suspended Nov 8th 2010 ending net bank debt projected at $242 MM 18

19 Balance Sheet Investor Concerns: High net debt may be a barrier to realizing our potential Total debt to cash flow ratio looks strip pricing Hedge crystallization has added focus on 2011 Not all debt is created equal 70% of convertible debentures or 34% of total debt are not due until 2015 Market for refinancing of convertible debentures remains strong Significant chance of conversion of debentures to common shares with gas price recovery We have had great success in debt reduction: Total debt has decreased 24% since Q2 Dispositions have had little effect on production and cash flow Currently have $125 million in room (36%) on bank line We have the ability to service our debt Further debt reduction initiatives are underway Debt metrics look dramatically different even with modest gas price recovery In the event that gas prices don t recover we have large impact value items with liquidity We Have a More Bullish View on Gas Prices than the Market Balance Sheet Debt Reduction Birchwavy Acquisition - $130 $650 $600 $550 $500 Office Building Sale - $36 MM Crown Sales- $19 MM Elmworth Montney Profound Acquisition - $81 MM Cardium Edson Acquisition - $71 MM Wilrich $650 $600 $550 $500 $450 $450 $400 $400 $350 $350 $300 $300 $250 $250 $200 $200 $150 Q207 Q307 Q407 Q108 Q208 Q308 Q408 Q109 Q209 Q309 Q409 Q110 Q210 Q310 EQ410 E Bank Debt Net of WC Convertible Debentures Debentures for Debt Bank Debt for Acquisition $150 Total Debt Reduced 24% Since Q

20 Fourth Quarter Sensitivities Current Forward Market (1) AECO Monthly Index (1) ($/GJ) $ 3.00 $ 4.00 $ 5.00 Oil and Natural Gas Production (MMcfe/d) Perpetual Realized Gas Price ($/Mcfe) Funds Flow from Warwick Gas Storage ($millions) Total Funds Flow ($millions) Funds Flow Per common share ($/common share/month) Payout Ratio (2) (%) Ending Net Bank Debt ($millions) Convertible Debentures ($millions) Gas storage funding arrangement liability (4) ($millions) Ending Total Net Debt (3) ($millions) Ending Net Debt To Funds Flow Ratio (times) Ending Total Net Debt to Funds Flow Ratio (times) (1) Average AECO settled and forward price for October - December 2010 as at Nov. 8, 2010 was approximately $ 3.52 /GJ (2) Estimated payout ratio assumes distribution rate of $0.03/month per common share through December 2010 (3) Calculated as ending net debt (including convertible debentures) divided by estimated annual 2010 funds flow (4) Gas storage funding arrangement reflects a future delivery obligation of 8 Bcf of natural gas to the counterparty in Q Ending Net Bank Debt to 2010 Funds Flow Ratio Projected at 1.1 Times Investment Thesis PMT presents tremendous leverage to what we believe will be a strong recovery in natural gas prices Market is giving very little credit to the transitioning and repositioning of our asset base towards higher impact opportunities PMT continues to provide a very attractive yield Balance sheet improvements are not widely understood The absolute amount of leverage has decreased by 24% since Q Bank debt has decreased 41% since Q despite very weak gas prices Significant internal opportunities to continue to manage leverage Focused on Maximizing Shareholder Value 20

21 Opportunity Inventory Risk Discounted Reserve Report + Current Recorded Prospect Inventory 2009 Year End P + P Reserves = Bcfe Risk-Discounted Additional Reserve Potential = 598 Bcfe GOB Recompletions Conventional Drilling UnConventional Tight Shallow Gas Resource Plays (Viking, Colorado) Proved + Probable Undeveloped Proved + Probable Developed + Gas Storage + Option Value NE AB Bitumen CO2 Sequestration & Storage Mannville CBM Tight oil and Gas Exploration Oil/Oil Sands Projects UnConventional Tight Gas Resource Plays (Montney, Rock Creek Notikewin) Conventional Oil Unconventional Tight Oil (Cardium) Reserves represent >50% of risk-discounted reserve and value potential Opportunity Inventory -Unrisked Reserve Report Current Recorded Prospect Inventory 2009 Year End P + P Reserves = Bcfe Unrisked Additional Reserve Potential = 2,236 Bcfe Proved + Probable Undeveloped GOB Recompletions Conventional Drilling Proved + Probable Developed UnConventional Tight Shallow Gas Resource Plays (Viking, Colorado) + Gas Storage + Option Value NE AB Bitumen CO2 Sequestration & Storage Mannville CBM Tight oil and Gas Exploration Oil/Oil Sands Projects UnConventional Tight Gas Resource Plays (Montney, Rock Creek Notikewin) Conventional Oil Unconventional Tight Oil (Cardium) As technical understanding advances, risk assessment adjusts and risk-discounted potential grows 21

22 Net Asset Value with Prospect Inventory Risk Discounted McDaniel January 2010 prices NPV 8% (MM$) $2,000 $1,500 $1,000 $500 $- $(500) $(1,000) Risked 8%: $ /Share Reserve Based 8%: $ 6.92 /Share Liabilities Assets Risked $14 $13 $12 $11 $10 $9 $8 $7 $6 $5 $4 $3 $2 $1 $- $(1) $(2) $(3) $(4) $(5) $(6) $(7) Bitumen In-Situ Viking & Colorado Shale Tight Shallow Gas Montney Gas Pembina Cardium Light Oil Deep Basin Tight Gas Resource Play Conventional Shallow Gas Gas Over Bitumen Proved + Probable UnDeveloped Proved + Probable Developed (1) December 31, 2009 reserves adjusted for 2010 dispositions and acquisitions (2) Mark-to-McDaniel s value of Perpetual hedge book at January 1, 2010 ($50 MM) (3) Bank debt and convertible debentures at June 4, 2010 net of estimated working capital; net of dispositions (4) FMV of Undeveloped Land $143 MM TriOil Hedge Book Net ARO Convertible Debenture Bank Debt Net Asset Value with Prospect Inventory Unrisked Potential McDaniel January 2010 Prices $5,000 $4,000 UnRisked 8%: $ /Share $33 $29 Bitumen In-Situ Viking & Colorado Shale Tight Shallow Gas Montney Gas $25 Pembina Cardium Light Oil NPV 8% (MM$) $3,000 $2,000 $1,000 $21 $17 $13 $9 $5 Deep Basin Tight Gas Resource Play Conventional Shallow Gas Gas Over Bitumen Proved + Probable UnDeveloped Proved + Probable Developed TriOil Hedge Book $- $1 Net ARO $(3) Convertible Debenture $(1,000) Liabilities Assets UnRisked $(7) Bank Debt (1) December 31, 2009 reserves adjusted for 2010 dispositions and acquisitions (2) Mark-to-McDaniels value of Perpetual hedge book at January 1, 2010 ($50 MM) (3) Bank debt and convertible debentures at June 4, 2010 net of estimated working capital; net of dispositions (4) FMV of Undeveloped Land $143 MM 22

23 Perpetual Energy Inc. (TSX: PMT) Low cost base assets well suited to sustainable partial cash flow distribution model Dividend at $0.03 per share per month Premium yield at low payout ratio Extensive inventory of base opportunities to fuel production and reserves replacement and generate future cash flow Cash flow generators to fund dividends and capitalize growth Exposure to multiple, exciting Game Changers to drive future growth Option Value intrinsic to asset base Extensive NE Alberta in-situ bitumen potential Emerging exploration in core areas and new ventures Improving balance sheet to take advantage of opportunities Track record of success making strategic value-driven acquisitions Accountable and entrepreneurial team, motivated by excellence Focused on Maximizing Shareholder Value 3200, Avenue SW Calgary, Alberta CANADA T2P 3H TOLL FREE PHONE FAX info@perpetualenergyinc.com WEB FOR ADDITIONAL INFORMATION: Sue Riddell Rose President & CEO Cam Sebastian VP Finance & CFO Sue Showers Investor Relations & Communications Advisor 23

24 Appendix Appendix - Q Operating Highlights Actual and deemed production grew 3% to MMcfe/d from MMcfe/d in Q Actual production averaged MMcfe/d as compared to MMcfe/d in Q Cost reduction initiatives enhancing competitiveness, profitability and efficiency Q3 Operating costs down 11% to $24.9 MM ($1.79 per Mcfe) year over year Excluding gas storage expenses of $0.9 MM, operating costs decreased 14 % to $1.71 per Mcfe for Q Year to date operating costs reflect a 15% reduction on a unit-of-production basis of $1.66 per Mcfe 24

25 Appendix - Q Capital Spending Highlights Third quarter capital expenditure program of $27.6 MM delivers positive results $12.8 MM spent in West Central Alberta Carrot Creek/Edson Cardium Oil o Drilled 2 gross (1.5 net) new HZ wells and completed 2 additional HZ wells o To date participated in 5 (3.2 net) HZ wells First 4 wells averaged ~175 BOE/d per well for first 30 days Fifth well currently undergoing completion Wilrich Sand Liquids-Rich Gas o 3 gross vertical completions delineated reservoir extent o 1 HZ well (1.0 net) drilled; average production rate of 4.25 MMcf/d and 40 bbls/mmcf of NGL s and condensate Elmworth Montney Liquids-Rich Gas o Carried interest on 3 commited delineation wells First well drilled in Q3; Second well currently drilling o Recent completion testing 7.5 MMcf/d with associated liquids on clean up $7.8 MM in Eastern Alberta o Drilled 9 gross (7.5 net) heavy oil wells at Birchwavy East o Drilled 6 gross (6.0 net) unconventional Viking wells at Craigend including one HZ o Drilled 4 gross (4.0 net) shallow gas wells in Birchwavy East $7 MM on new ventures activity, seismic and Crown land purchases Appendix - Q Warwick Gas Storage Warwick Gas Storage ( WGSI ) facility construction is proceeding as scheduled Fully operational for natural gas injection which commenced on May 1, 2010 at rates of up to 175 MMcf/d of third party natural gas Q3 capital spending of $23.1 MM for purchase and installation of compression facilities for withdrawal phase $46.3 MM spent in first nine months of 2010 Budgeting capital of $7 MM in Q4 to complete facility construction and drill one new well Commissioning and facility testing in November

26 Appendix - Q Financial Highlights Realized gas price of $6.18 / Mcfe in Q3 2010, 166% of the AECO Monthly Index price of $3.72 / Mcf Realized hedging gain of $29.4 million Funds flow of $46.1 million ($0.32 per common share) Net bank debt reduced by $38.6 million during Q to $256.9 million from $295.5 MM at June 30, 2010 Dividends payable for the third quarter of 2010 totaled $0.15 per share, comprised of $0.05 per share paid on August 16, September 15 and October 15 Payout ratio for Q of 47% as compared to 31% in Q Since inception to October 15, 2010 Perpetual has paid out approximately $1.1 billion in distributions/dividends dst buto s/d de ds Appendix Q Financial Results ($ millions except per Share amounts) Three Months Ended September % Change Nine Months Ended September % Change Revenue (14) (10) Funds Flow (23) (13) Per Share (35) (28) Dividends Per Share (8) Net Earnings (Loss) (1.7) (44.7) (96) (8.7) 24.9 (135) Per Share (0.01) 01) (0.36) (97) (0.06) 06) (127) E&D Capital Expenditures Net Debt (1) Net Debt to annualized funds flow (1) Net bank debt and convertible debentures Q3 Payout Ratio 47%; YTD Payout Ratio 37% 26

27 Appendix Q Operating Results Three Months Ended September % Change Nine Months Ended September % Change Total Production (Bcfe) (4) Daily Production (1) (4) (MMcfe/d) Per Share (cfe/d/common share) Natural Gas Price, before hedging ($/Mcfe) (13) (17) Natural Gas Price, after (18) (8) hedging ($/Mcfe) Unit Operating Costs ($/Mcfe) Wells Drilled (gross/net) (10) (15) 23/22.5 4/ /492 63/ / /69 Q3 Actual and Deemed Production MMcfe/d 27