Perpetual Energy Inc.

Transcription

1 Perpetual Energy Inc.

2 Forward Looking Statements 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, 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

3 Market Profile Common shares outstanding million Management ownership 24.4% Share price (5 day weighted average) $ 1.59 Market capitalization Convertible debentures Senior unsecured notes Net bank debt Enterprise value $ 225 million $ 235 million $ 150 million $ 120 million $ 730 million 30 day weighted average trading volume (Approx) 835,000 shares Dividend suspended October

4 Perpetual Strategy The Last 24 Months Build a diversified portfolio of material repeatable, high return assets for growth Capture material positions in chosen strategies De-risk game changers at appropriate pace to manage risk Categorize assets for long term portfolio Grow & harvest (keepers) Sustain & divest (funders) Increase funds flow netbacks Increase oil and NGL production Drive to a lower cost structure Divest of funders when timing appropriate to optimize value and decrease debt Maintain exposure to gas price recovery Transition shareholders fairly to growth-oriented corporation Transitioning from 100% conventional shallow gas to diversified, resource-style, growth-oriented asset base through declining gas price environment 3

5 $/Mcfe $/Mcfe Historical Funds Flow Netbacks Funds flow netbacks maintained for 2 extra years after gas price collapse due to hedging program Excess funds flows from hedging directed to transition assets, modest debt reduction and dividends ~$90 MM reinvestment required to sustain; ~$135 MM to grow at $3MM/MMcf/d ($18,000 per flowing BOE) production addition capital efficiency Significant measures taken to increase future netbacks Operating costs and royalties reduced significantly Focusing development capital to increase top line revenue with higher priced oil and NGLs $9.00 $8.00 $7.00 $6.00 $5.00 $9.00 $8.00 $7.00 Hedging Gains Revenue, including hedging Revenue, excluding hedging Royalties Interest General and Administrative Operating Costs Cash Flow Netback Dividend Per Mcfe Exploration and Development Capital $4.00 $6.00 Hedging Gains $3.00 $5.00 $2.00 $1.00 $4.00 $3.00 $2.00 (1) $0.00 $ E 2012E (1) 2012 assumes $85 million capital expenditure program, $4.00 AECO $0.00 natural gas price, $95 WTI oil price, oil and liquids production of 3,400 bbl/d and gas production of 120 MMcf/d E 2012E Netbacks poised to increase with increased oil and NGL in commodity mix 4

6 Sustainable Growth Plus Income Strategy DIVIDENDS: Target Sustainability BASE CASH FLOW GENERATORS: Target to Minimize Production Declines and Maximize Free Cash Flow DIVERSIFYING GROWTH STRATEGIES: Target Value And Cash Flow Growth and Diversification Targeting a sustainable income plus growth model 5

7 Assets and Operations

8 Asset Base Transition Strategy The Last 24 Months Asset Portfolio Characteristics Generate superior returns on investment Predictable and repeatable Material in size and scope and scalable Opportunity-rich with probability for secondary targets and value to evolve Operational and execution control and excellence Attractive and easily understood risk and return potential for investors Diversified to manage risks (commodity price, technical, operational, regulatory) Within our risk-tolerance and financial capabilities Chosen strategies Opportunities where we can take advantage of operational, technical and geographic synergies and expertise in eastern Alberta Resource-style liquids-rich gas in Alberta deep basin Existing ownership of opportunities (eg Gas Storage, optimize non-core assets) Tight oil in Alberta Working to Define Keepers and Funders 7

9 Operating Profile Eastern Alberta Conventional Shallow Gas Gas over Bitumen Technical Solutions Mannville Heavy Oil Viking/Colorado Shallow Shale Gas Bitumen Near Cold Flow Panny Bluesky Bitumen Thermal Liege Carbonates Warwick Gas Storage Deep Basin West Central Alberta Liquids-Rich Gas Edson Wilrich Elmworth Montney Carrot Creek Cardium New Ventures Tight Oil and Gas Exploration TriOil Resources (4%) Actual & Deemed Production (Q3 2011) Natural Gas (92.6%) NGL s and Oil (7.4%) Gas over Bitumen Deemed Production (1) P+P Reserves (2) Reserve to Production Ratio (P+P) (RLI) Contingent Resource - Elmworth Montney (2) Contingent Resource - Panny Bluesky Bitumen (3) Contingent Resource - Liege Carbonates Bitumen (3) Warwick Gas Storage Working Gas Capacity 27,550 Boe/d 124 MMcf/d 1,995 bbl/d 30 MMcf/d 488 Bcfe 8.9 Years 145 Bcfe 108 MMbbl 66 MMbbl 17 Bcf (1) Cash Flow = 0.5 x [(deemed production volume x 0.80) x (Alberta Reference Price - $0.3791/GJ)] (2) As evaluated by McDaniel and GLJ at year end 2010 (3) As evaluated by McDaniel in

10 Entrepreneurial Approach to Value Creation CASH FLOW GENERATORS DIVERSIFYING GROWTH STRATEGIES OPTION VALUE Sustainable Cash Flow Generators Legacy Conventional Shallow Gas in Northeast & East Central Alberta + Invest For Growth Deep Basin Liquids-rich Tight Gas West Central Alberta Edson Liquids-rich Wilrich Gas Eastern Alberta Heavy Oil + Exposure to Emerging Technologies GOB Technical Solutions NE Alberta Bitumen in Carbonates Tight Oil & Gas Exploration + + Optimize and Advance TriOil Resources (4%) Warwick Gas Storage Pembina Cardium Tight Oil Elmworth Montney Gas Viking / Colorado Shale Gas Panny Bitumen = SHAREHOLDER VALUE 9

11 Base Legacy Assets Conventional Shallow Gas East Central and Northeast Alberta Cretaceous and Devonian sweet shallow gas Belly River Viking Grand Rapids Lower Mannville Pre Cretaceous Unconformity 75% of production base 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 Historical drilling success > 90% Seismic definition and step out of infrastructure drive prospects to drill ready 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 Average well $0.4 MM D C & E Risked IP 300 Mcf/d; EUR 0.3 Bcf (<$25,000/BOE/d; <$1.77/Mcf) Extensive inventory to minimize production declines at industry-leading capital efficiencies 10

12 Diversifying Growth Strategies Chosen Key Priorities

13 Eastern Alberta - Conventional Heavy Oil Mannville Lloyd ~3D coverage Sparky HZ Growing low-risk heavy oil drilling inventory in excess of 100 drill-ready locations Geographically synergistic with shallow gas assets Production established from 6 Mannville pools 5 Lloydminister; 1 Sparky > 82 MMbbl Original Oil in Place 4.1 5% recovery factory Low cost HZ development HZ ~$950K/well bbl/d initial rate/well Production 718 bbl/d Q average 1,050 bbl/d Q exit ~1,400 bbl/d year end forecast exit 2011 Activity Sparky 1 st HZ IP 125 bbl/d; Cum >16 Mbbl oil since April 1/11 9 HZs in Q2/Q3 producing ~1,000 bbl/d, onstream Mid-Aug/11 2 horizontal pool extensions planned for Q Lloydminster 3 existing pools with historical modest vertical production 1 st HZ IP 240 bbl/d; Cum >22.5 Mbbl oil since Mar 23/11 2 new pools confirmed in Q3/Q4 production start up ongoing Infill program of 7 horizontals underway in Q vertical exploration well targeting new pool in Q4 Evaluating waterflood and other enhanced recovery Additional exploration ongoing 3 exploration prospects vertically drilled in Q3 - evaluating additional exploration prospects identified and captured Extensive in-house 3D & 2D seismic 123,000 net acres of lands 12

14 Sparky Type Curve GRAPH OF PRODUCTION RESULTS FROM LINDA 2 additional wells to be spud before year end Average initial rate over 100 bbl/d; low decline rate 13

15 Mannville Lloyd Development Plan Example Lloyd Channel 2011 Simulate development options 1st phase complete 2011 HZ Drills (ongoing & encouraging) 2 Channel (1 st 22.5 Mbbl cum prod) 4 Lower Regional 3 Upper Regional Redo History match 2012 Forecast Sensitivities Ultimate well spacing Multi-laterals Waterflood design Submit waterflood application Middle Regional Lloyd 2011 Capital Budget 2012 Capital Program Construct central battery Drill 12 infill wells Future Location Current Producer Pool Outline Non WI lands 1 mile Lower Regional Lloyd Reserve Scope (5% recovery factor) Lloyd Channel: 771 Mbbl Middle Regional: 471 Mbbl Lower Regional: 488 Mbbl Original Oil In Place >35 MMbbl At ~15% Recovery Factor Recoverable OIP is 5.2MMbbl; Recovery to date <1% (325 Mbbl) 14

16 Deep Basin Liquids-Rich Gas West Central Alberta Edson Deep Cut Plant 375 MMcf/d capacity ROSEVEAR Edson Shallow Cut Plant (30% WI) 30 MMcf/d capacity South Rosevear Shallow Cut Plant (15% WI) 75 MMcf/d capacity Multi-Zone Area Targeting Viking, Bluesky, Wilrich, Lower Mannville, Fernie Sand & Rock Creek Liquids-Rich Gas bbls/mmcf NGL s Extensive facility network Interest in 3 gas processing facilities Excess third party capacity ANSELL Perpetual Lands Perpetual WI Facilities Perpetual Pipeline Pipeline to Wolf South Alliance Pipeline Other Facilities Other Pipelines Rock Creek HZ loc Notikewin HZ loc Wilrich HZ loc EDSON Compressor (100% WI) 30 MMcf/d capacity WEST PEMBINA CARROT CREEK Extensive prospect inventory 30 Recompletions 40 Multi-zone vertical drills Average depth = 2,450m ~$1.6 MM D C & E Risked IP MMcf/d Risked EUR 0.7 Bcfe 20 horizontal locations (excl. Wilrich) ~$3.5 MM D C & E Risked IP 2 3 MMcf/d Risked EUR Bcfe >80 Wilrich horizontal locations ~$5 MM D C & E Risked IP 4 MMcf/d Risked EUR 3.7 Bcfe Establishing operational excellence in vertical and horizontal development 15

17 West Central Alberta Resource Projects Edson Wilrich Pipeline To Edson Deep Cut Plant 36 bbl/mmcf NGLs (50% condensate) To South Rosevear Plant (15% WI) Ansell Edson Compressor Capacity 30 MMcf/d Exploration Doubled Wilrich land position in 2011 Future Wilrich Development Locations 80 net and growing Horizontal Well Q3 HZ drills Q4 HZ drills Q4 Vertical Well

18 Wilrich Value Potential Economics per Drilling Location Capital (D,C & T) $4.9 MM 10 % $2.7 MM BT ($3.5 MM BT) ROR 39% BT (50% BT) F&D $10.70/ BOE Capital Efficiency <$12,000 BOE/d Pricing Operating Costs Well Depth Type Curve Reserves Royalties Risk Assumptions $4/Mcf; $75/bbl WTI = $53.20/bbl NGLs ($4/Mcf; $95/bbl WTI = $66.30/bbl NGLs) $6.45/BOE 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 3 Bcfe per well 5% new well royalty rate for 500 MMscf Unrisked Flare while drilling 13-5 Wilrich HZ Preparing to Frac 13-5 Wilrich HZ Pad completion in section 5 Strong operating netbacks - $5.80/Mcfe revenue on AECO gas price of $3.66/Mcf 17

19 Other Diversifying Growth Strategies Optimize and Advance

20 West Central Alberta Resource Projects Elmworth Montney 92 Gross Sections of Montney Exposure 50/50 Joint Venture with Tourmaline at Elmworth 100% WI in Karr block Reserves and Contingent Resource 32 Bcfe net P+P reserves booked 145 Bcfe net best estimate additional contingent resource 34 gross (17 net) sections not yet evaluated (SW Block) Competitor activity in past 18 months 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 Technical Viability of Play Confirmed 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 ELMWORTH Perpetual Locations Montney Producers Perpetual Lands KARR >1 TCF original gas in place (gross) Resource potential established Working towards area development plan 19

21 Elmworth Montney Prospect Inventory POD 2 Initial Development POD C B A Drilled & Tested Inline Flow Test currently being conducted Drilled & Tested Initial Development 50 MMcf/d gross POD Drilled & Tested Gross Startup Activities per Development Pod 12 Upper Montney wells Compression Separation Dehydration Facilities Associated P/L Gathering Systems Gross Start Up Capital $ million POD 3 12 wells drilled plus facilities in Year 1 Drill to fill ~ 4-6 gross wells/year thereafter Total of ~50 wells per POD >150 Identified Future Undeveloped Locations 20

22 West Central Alberta Resource Projects Cardium Tight Oil EDSON CARROT CREEK PEMBINA NOTE: Only Cardium producing wells shown Light oil in tight sand halo ~200 Boe/d Cardium production 24 net sections of undeveloped Cardium rights HZ well costs: $3MM DC&T Type curve: IP 150 BOE/d Reserves 150 Mboe Perpetual Cardium Lands Producing Cardium Wells Perpetual 2011 Cardium HZ Cardium HZ Locations/License 6 mi Intense industry activity exploiting light oil from tight cardium in West Pembina 21

23 Carrot Creek Cardium Vero Section W5 development 4 (3.5 net) Hz wells drilled; production start-up late March Production ~200 Boe/d Undeveloped Land Disposition 21 gross (12 net) sections of undeveloped Cardium rights sold for $14 million in May 2011 Disposed of higher risk silty locations Joint Venture 2 well commitment Pays 100% to earn 55% of Perpetual interest in one section Rolling option on same terms for 11.5 net sections Exposure to upside on farmout lands Vermillion CNRL 29.9 net locations Drilled HZ Wells Vero Bonterra Vermillion Perpetual Cardium Other Perpetual Lands May 2011 Cardium Rights Sold Value capture through asset disposition and joint venture activities 22

24 Warwick Gas Storage 40 Bcf Storage Reservoir 10 Bcf base reserves cushion gas in place 8-11 Bcf additional operating cushion Up to 25 Bcf potential working gas capacity 1.2 to 1.5 cycle facility WGSI Storage Leases Warwick Glauconitic -Nisku A Pool WGSI Leases Well Site Pad Compressor Facility Pipeline Horizontal Wells H Hz Well H Hz Wells mi 2-19 Grass Roots Gas Storage Development of existing depleted gas pool Commercial Park and Loan business Funded through forward sale of base reserves cushion gas MTM ~$40 million Delivery obligation for 8 Bcf of cushion gas in Q Expect physical gas to settle obligation at end of life Test Cycle Injection: May-Oct 2010 Facility Construction Q2-Q Capable of > 200 MMcf/d withdrawal Test Cycle Withdrawal: Jan-March Bcf new HZ wells drilled Cycle 2 working gas set at 17 Bcf 23

25 Resource Projects - Viking / Colorado Tight Shallow Gas Belly River Play Fairway Cardium/ Colorado Wells Perpetual Lands Viking Proved Undeveloped Viking Probable Undeveloped Viking Proven Non-Producing Prospect Inventory 5 Yr Vast Tight Shallow Gas Play Booked Reserves (Viking Only) 6 Bcf P+P Producing 15 Bcf P+P Developed Non-Producing 111 Bcf P+P Undeveloped 837 Vertical 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 advanced technical study 3 vertical drills coring 200m each of Colorado/ Viking interval for detailed geological, geomechanical and geochemical analysis Q1-Q Detailed special core analyses Gas in Place Analysis Production inflow and fracture modeling Q Multi-well pilot plan for Colorado Group, incorporating detailed core analysis and fracture and inflow modeling, to be determined Pilot primarily existing well recompletions 2012 Incorporate learnings from pilot into commercial trials and full scale execution 24

26 Bitumen Lands 526 net sections (336,000 net acres) of oil sand leases 7 discrete project areas Various formation targets and ultimate recovery methods 2011 Q1 Activity Tested 4 project areas - South Liege, Hoole, Panny and Clyde 9 verticals; 1 Hz Perpetual OS Leases Primary Projects SAGD Projects Fireflood Projects CSS Projects Electric Heaters Oil Pipelines 25

27 Bitumen Panny Bluesky 8m Bitumen 10m Bitumen 2010/11 Vertical Locations 2010/11 Horizontal Locations Q Drilled 3 vertical, 1 HZ to evaluate possibility of cold flow in greater Panny area Established low rate flow without solvent or thermal assistance Average pay thickness 11 m Fairly low viscosity bitumen ~15, C Resource Assessment (McDaniel) 618 MMbbl OBIP (P50) 108 MMbbl Contingent Resource (P50) assigned utilizing horizontal cyclic steam Future drilling planned targeting contingent resource expansion Submitted application for pilot test 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 26

28 Bitumen Liege Carbonates R 22 R 21 R 20 R19 W4 T95 GROSMONT NET BITUMEN m 3 Grosmont carbonate / Leduc wells drilled in Q to evaluate resource Stacking of 3 Grosmont units; > 30 m pay T94 T m >30 m Leduc reef facies present and bitumen saturated in places; geologically complex Resource Assessment (McDaniel) 2,327MM bbl bitumen in place 66 MM bbl contingent resource assigned 400 MM bbl prospective resource assigned 20% recovery factor applied using SAGD as technology under development T92 T91 T90 T89 Q OV Wells Perpetual Oil Sand Leases Leduc Reef Excellent reservoir quality vuggy porosity in Grosmont 27

29 Q Highlights

30 Q Operational Highlights - Production Actual and deemed production averaged MMcfe/d, down 6% from Q Gas over Bitumen Shut-in of 8 MMcf/d at Liege Dispositions of non-core assets including 5.2 MMcfe/d Production declines partially offset by gains in Wilrich liquids-rich gas & Mannville heavy oil Oil and NGL production increased 71% to 1,995 bbl/d Production from resource-style plays in the Deep Basin increased 26% to 32.3 MMcfe/d Represented 24% of total actual production, up from 17% of production in Q Mannville heavy oil production growth taking hold Q3 production averaged 718 bbl/d versus 177 bbl/d in Q Q3 exit rate of 1,050 bbl/d and growing as new drills begin pumping and are optimized Oil and NGL production increases reflect positive impact of commodity diversification strategy 29

31 Q Operational Highlights - Costs Cost reduction initiatives enhancing competitiveness, profitability and efficiency Q3 operating costs down 10% year over year to $22.5 MM ($1.79 per Mcfe) Year to date operating costs flat on a unit-of-production basis at $1.65 per Mcfe despite increased percentage of oil production with higher operating costs relative to gas operations Q3 Cash G&A expenses down 27% year over year to $6.9 MM ($0.50 per Mcfe) Continuing to lower cost structure 30

32 Q Capital Spending Highlights E&D capital expenditure program of $38.4 MM delivers positive results $21.5 MM spent in West Central Alberta Liquids-Rich Gas Edson 3 (3.0 net) horizontal wells and 1 (1.0 net) vertical well drilled; On stream in October $4 MM in land spending to expand play to West Edson and double prospect inventory Additional horizontal re-entry and recompletions Karr Completed 1 vertical and 1 horizontal (2.0 net) Dunvegan wells o HZ Well came on in October at 5.0 MMcf/d with 200 bbl/d of NGLs o 4 Follow up HZ Dunvegan locations; Montney potential identified $15.5 MM in Eastern Alberta - Primarily Heavy Oil Facilities and production start-up operations for Q2 Sparky pool development wells Drilled 9 (9.0 net) wells for Mannville Heavy oil play at Birchwavy East o 3 (3.0 net) Sparky horizontal development wells o 1 vertical exploration and 1 horizontal development (2.0 net) well in new Lloyd pool o 3 (3.0 net) vertical exploration wells o 1 (1.0 net) water disposal well Modest spending on shallow gas recompletions and Viking/Colorado 3G technical project $0.3 MM on Panny bitumen pilot application Focused spending on liquids-rich gas and heavy oil drilling 31

33 Q Capital Plan Recompletion / Workovers, $0.7 Bitumen, $0.7 East Heavy Oil, $10.0 Maintenance Capital, $0.1 Warwick Gas Storage, $0.8 Conventional Gas Activity, $1.4 Wilrich Liquids-Rich Gas, $16.7 Q Capital Budget: $31.2 MM Heavily weighted to oil and liquids-rich gas to accelerate commodity diversification Focus on Wilrich and Mannville heavy oil Wilrich Liquids-Rich Gas 1 (0.5 net) horizontal evaluation well in West Edson 2 (1.1 net) development wells in Edson proper 1 (1.0 net) vertical exploration well Edson trend extension Carrying partner interests to earn additional lands Mannville Heavy Oil 2 vertical Lloyd exploration wells 9 HZ Lloyd development wells 2 HZ Sparky development wells ~80% of total spending targeting oil and liquids rich gas projects 32

34 Q3 Financial Highlights Realized gas price of $3.75/Mcf versus $6.02/Mcf in Q Realized hedging gains in 2010 of $29.4 MM versus $2.2 MM in Q Realized oil and NGL price of $70.15/bbl versus $56.13 for Q Funds flow of $19.3 million ($0.13 per common share) Net bank debt at $120 million on $210 million credit facility Dividends payable for the third quarter of 2011 totaled $6.6 MM or $0.045/share Consisting of $0.015 per common share paid on August 15, September 15, and October 17 On October 19 th, 2011 the dividend was suspended until further notice Focused on Growing Value for Shareholders through Diversification Strategy 33

35 Diversification Strategy Summary

36 Annual Average Production (Mcfe/d) % Diversifying Growth vs Legacy Diversification Strategy - Resource Growth Plays Growth vs Legacy Assets Legacy Shallow Gas Production GOB Deemed Production Diversifying Growth Assets 2011 YTD Dispositions % Diversifying Growth Assets (Excluding Deemed) 210,000 50% 190,000 45% 170,000 40% 35% 150,000 30% 130,000 25% 110,000 20% 90,000 70,000 15% 10% 5% 50, F 0% 8 fold increase in production from resource-style growth assets in two years 35

37 bbl/d Diversification Strategy - Oil and Liquids Production 3,000 14% 2,500 12% 2,000 1,500 1, % 8% 6% 4% 2% 0 0% Q110 Q210 Q310 Q410 Q111 Q211 Q311 Q411E Eastern Oil (BBL/d) West Central Oil and Liquids (BBL/d) % Liquids 188% increase in oil and liquids production in two years 36

38 $MM Cash Flow Diversification - Oil and Liquids Revenue 20 30% 15 20% 10 10% 5 0% 0 Q110 Q210 Q310 Q410 Q111 Q211 Q311 Q411E -10% Oil and Liquids Revenue %Liquids 200% increase in oil and liquids revenue in two years 37

39 Commodity Diversification 2012 Funds Flow (86% gas, 14% Oil; 18 Bcf Cycle) AECO($/GJ) WTI ($/bbl) Note: Assumes 120 MMcf/d of gas and 3,400 bbls/d of oil production 88% : 12% Funds Flow (80% gas, 20% Oil; 18 Bcf Cycle) AECO($/GJ) WTI ($/bbl) Key Assumptions: Production: Maintain 140 MMcfe/d flat 20% base decline 2011 oil and liquids ratio 9% Capital $85 million capital program in 2012 and 2013 to maintain production $3MM/MMcfe production addition costs Gas Storage Cash Flow $10 MM (18 Bcf working gas) 2012 Oil Hedging Costless collar 1500 bbl/d; $92.25 Free cash flow over and above capital Current forward commodity prices (November 8, 2011) Note: Assumes 113 MMcf/d of gas production and 4,700 bbl/d of oil production 80% : 20% 38

40 Balance Sheet

41 Balance Sheet Current Net Bank Debt : ~$120 million Current borrowing base on credit facility - $210 million Semi-annual redetermination November 30, 2011 Senior Unsecured Notes: $150 million Coupon Rate %; Maturity date - March 2018 Convertible Debentures: $235 million PMT.DB.C repayable with bank debt or with equity at Company discretion $160 million effectively represents long term debt with 2015 maturities TSX Symbol Amount Outstanding Coupon Rate Conversion Price Maturity Date 5 Day Weighted Avg. Trading Price PMT.DB.C $ 74.9 million 6.50% $ June 30, 2012 $ PMT.DB.D $ million 7.25% $ 7.50 January 31, 2015 $ PMT.DB.E $ 60.0 million 7.00% $ 7.00 Dec. 31, 2015 $ Total Net Debt: ~$505 million ~60% of total net debt has term of 3 years or greater 40

42 Balance Sheet Debt Reduction while Asset Repositioning Birchwavy Acquisition - $130 MM Viking/ Colorado Shale Profound Acquisition - $81 MM Cardium Office Building Sale - $36 MM $600 Elmworth Montney - $19 MM Edson Acquisition - $71 MM Wilrich $600 $500 $500 $400 $400 $300 $300 $200 $200 $100 $100 $0 Q207 Q307 Q407 Q108 Q208 Q308 Q408 Q109 Q209 Q309 Q409 Q110 Q210 Q310 Q410 Q111 Q211 Q311 Bank Debt Net of WC Convertible Debentures Debenture Issue Bank Debt for Acquisition Senior Notes $0 Total debt reduced 23% since Q

43 2011 Q4 Funds Flow and Balance Sheet Sensitivities 2011 Q4 funds flow outlook Average AECO Gas Price ($/GJ) Natural gas production (MMcf/d) Oil and NGL production (bbl/d) 2,850 2,850 2,850 Realized gas price ($/Mcf) Total funds flow ($MM) Per Share ($/Share) Ending net bank debt ($MM) Ending net total debt ($MM) Ending net bank debt to annualized funds flow ratio (times) Ending net total debt to annualized funds flow ratio (times) Sensitivities incorporate a realized oil and NGL price of $78 per bbl, operating costs of $23 million, cash general and administrative expenses of $8 million and an interest rate on bank debt of 5.4 percent. 2. The current settled and forward average AECO price for 2011 as of November 8, 2011 was $3.52 per GJ. 42

44 Maximizing Shareholder Value

45 TOP 4 Strategic Priorities The Next 12 Months 1. Restore Healthy Balance Sheet Dividend suspension Net Dispositions of $75 to $150 million Repay PMT.DB.C in June in cash Option to repay in shares at Company s discretion Capital program funded within cash flow 2. Capital Investment in 2 Key Commodity-Diversifying Priorities Grow oil and NGL production profitably Wilrich liquids-rich gas Mannville heavy oil 3. Advance assessment of high impact opportunities with risk-managed investment Viking/Colorado Panny Bitumen Mannville heavy oil waterflood/eor 4. Manage downside risks Decrease costs Protect cash flow Maintain optionality for debt management Focused plan to weather bottom of gas price cycle and thrive in transition 44

46 Dividend Suspension Dividend suspended effective October 2011 Preferential capital investment in higher netback assets will strengthen balance sheet by increasing funds flow in combination with ongoing debt reduction initiatives Accelerating investment in promising oil and liquids-rich opportunities Strong economic potential of the Wilrich now well understood Growing inventory of heavy oil prospects in east central continuing to show significant promise Reinstatement evaluated once balance sheet health restored and commodity prices and costs support a sustainable model where excess free funds flow, above capital requirements, is generated for distribution to shareholders Dividend suspension driven by commitment to maximize shareholder value 45

47 Opportunity Inventory - Unrisked Reserve Report Current Recorded Prospect Inventory 2010 Year End P + P Reserves = 488 Bcfe Unrisked Additional Reserve Potential = 1,367 Bcfe Gas Over Bitumen Proved + Probable UnDeveloped + Gas Storage 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 + UnConventional Tight Shallow Gas Resource Plays (Viking, Colorado) Option Value Carbonate Bitumen Tight Oil and Gas Exploration GOB Technical Solutions TriOil Exploration Bitumen In-Situ Unconventional Tight Oil (Cardium) East Central Heavy Oil As technical understanding advances, risk assessment adjusts and risk-discounted potential grows 46

48 Sum of the Parts At $4 gas prices Asset Measure Valuation Range ($MM) Base Shallow Gas Reserve Report PV10% $480 Prospect Inventory 1,485 net locations and recompletions Resource Projects Reserve Report PV10% $145 Deep Basin 57 net locations Wilrich 80 net locations 160 East Central Heavy Oil 100 net locations 50 Montney 111 net locations Viking / Colorado 822 net locations Bitumen 182 MMbbls contingent resource Gas Storage Bcf working $6 MM / Bcf Investment in TriOil 1.3 MM shares 2-10 Total Assets $1, $1,800 Net Debt Sept 30, 2011 $(505) TOTAL NET VALUE $795 - $1,295 Source: Company Estimates $4/Mcf AECO gas price Per Share $ $8.75 Significant future value to be recognized from multiple assets Further leverage to gas price recovery upside 47

49 Investment Thesis Asset base repositioning for oil and liquids-focused opportunities successful Edson Wilrich in full scale development phase Conventional heavy oil development and low exposure exploration very promising Evolving commodity mix materially growing future funds flow and netbacks from 2011 lows High impact value potential from long term resource plays evident Elmworth Montney resource identified and scoping development scenarios Material bitumen in place and contingent resource defined at Panny and Liege Vast Viking/Colorado shallow shale gas fairway undergoing evaluation Non-depleting funds flow and value from gas storage asset established Sum-of-the parts analysis defines value well beyond current share price 65% of debt has term beyond 2014 providing flexibility Growing cash flow through diversification strategy will improve debt to cash flow ratios Multiple levers available to manage balance sheet - timing is now for asset sales Tremendous leverage to any gas price cycle recovery Every $0.50 per Mcf = $20 million of annual funds flow Strategically setting in place the inter-locking pieces for a strong growth strategy 48

50 3200, Avenue SW Calgary, Alberta CANADA T2P 3H TOLL FREE PHONE FAX info@perpetualenergyinc.com WEB FOR ADDITIONAL INFORMATION: Susan L. Riddell Rose President & CEO Cameron R. Sebastian Vice President, Finance & CFO Claire Rosehill Business and Investor Relations Analyst

51 Appendix Q3 Financial Results ($ millions except per Share amounts) Three Months Ended September % Change Nine Months Ended September % Change Revenue (33) (38) Funds Flow (58) (63) Per Share (59) (66) Dividends (70) (54) Per Share (70) (57) Net Earnings (Loss) (24.3) (16.3) (50) (57.2) (72.5) 21 Per Share (0.17) (0.11) (55) (0.39) (0.52) 25 E&D Capital Expenditures Net Debt (1)

52 Appendix Q3 Operating Results Three Months Ended September % Change Nine Months Ended September % Change Total Production (Bcfe) (10) (8) Daily Production (MMcfe/d) Per Share (Mcfe/d/common share) Natural Gas Price, before derivatives ($/Mcfe) Natural Gas Price, after derivatives ($/Mcfe) Unit Operating Costs ($/Mcfe) Wells Drilled (gross/net) (10) (8) (7) (12) (6) (8) (28) (35) / /22.5 (35)/(33) 23/ /59.5 (64)/(62) 51