Forward-looking statements

FirstEnergy Global Energy Conference September 15, 2014

Forward-looking statements This presentation contains forward-looking statements relating to Perpetual's business and operations that are based on management's current expectations, estimates and projections about its business and operations. Words and phrases such as "anticipates," "expects," "believes," "estimates," "projected," "future," "goals," "forecast," "plan," "opportunities," "upside," "will," "impact," "target," "2014 through 2015" and similar expressions are intended to identify such forward-looking statements. Such statements include, but are not limited to, statements pertaining to: Perpetual's business diversification and price risk management strategies which include the transitioning from shallow gas assets to resource-style, growth orientated oil and NGL assets and divestitures to optimize value and decrease debt; projected economics for various projects; future capital expenditure levels; the top strategic priorities for 2013 and beyond.these statements are not guarantees of future performance and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward-looking statements. You should not place undue reliance on these forward-looking statements, which speak only as of the date of this presentation. Unless legally required, Perpetual undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise. Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are: inaccuracies in the estimated timing and amount of future production of natural gas and oil due to numerous factors including permit delays or restrictions, weather, equipment failures, delays or lack of availability, unexpected subsurface or geologic conditions, lack of capital, increases in the costs of rented or contracted equipment, increases in labor costs, volumes of oil or gas greater or lesser than anticipated, and changes in applicable regulations and laws; unexpected problems with wells or other equipment, unexpected changes in operating costs and other expenses, including utilities, labor, transportation, well and oil field services, taxes, permit fees, regulatory compliance and other costs of operation; decreases in natural gas and oil prices, including price discounts and basis differentials; difficulties in accurately estimating the discovery, volumes, development potential and replacement of natural gas and oil reserves; the impact of economic conditions on our business operations, financial condition and ability to raise capital; variances in cash flow, liquidity and financial position; a significant reduction in our bank credit facility's borrowing base; availability of funds from the capital markets and under our back credit facility; our level of indebtedness; the ability of financial counterparties to perform or fulfill their obligations under existing agreements; write downs of our asset carrying values and oil and gas property impairment; the discovery of previously unknown environmental issues; changes in our business and financial strategy; inaccuracies in estimating the amount, nature and timing of capital expenditures, including future finding and development costs; the inability to predict the availability and terms of capital; issues with marketing of natural gas and oil including lack of access of markets, changes in pipeline and transportation tariffs and costs, increases in minimum sales quality standards for oil or natural gas, changes in the supply-demand status of gas or oil in a given market area, and the introduction of increased quantities of natural gas or oil into a given area due to new discoveries or new delivery systems; the impact of weather limiting or damaging operations and the occurrence of natural disasters such as fires, floods, hurricanes, earthquakes and other catastrophic events and natural disasters; the high-risk nature of drilling and producing natural gas and oil, including blow-outs, surface caterings, fires, explosions; the competitiveness of alternate energy sources or product substitutes; technological developments; changes in governmental regulation of the natural gas and oil industry potentially leading to increased costs and limited development opportunities; changes in governmental regulation of derivatives; developments in natural gas-producing and oil-producing countries potentially having significant effects on the price of gas and oil; the effects of changed accounting rules under generally accepted accounting principles and IFRS promulgated by rule-setting bodies; the amount of future abandonment and reclamation costs, asset retirement and environmental obligations; expected realization of gas over bitumen royalty adjustments; inability to execute strategic plans and realize projected economics, expectations and objectives for future operations and price risk management strategies; and the other risk factors identified in our most recent financial statements and management's discussion and analysis and Annual Informational Form and our other filings on SEDAR. Unpredictable or unknown factors not discussed herein also could have material adverse effects on our business and operations and on the forward-looking statements contained herein. Also included in this presentation are estimates of Perpetual's consolidated net debt after giving effect to the East Edson JV and 2014 and 2015 funds flow, which are based on the various assumptions as to production levels, capital expenditures, and other assumptions (including price assumptions for natural gas and oil disclosed in this news release and an exchange rate assumption of (US/CAD) $0.925 for 2014 and 2015. To the extent any such estimate constitutes a financial outlook, it was approved by management and the Board of Directors of Perpetual on June 24, 2014 and is included to provide readers with an understanding of Perpetual's anticipated funds flows based on the capital expenditure and other assumptions described herein and readers are cautioned that the information may not be appropriate for other purposes. 2

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

52% OF PRODUCTION >59% OF RESERVES 62% OF REVENUE >70% OF RESERVE VALUE

Perpetual Energy TSX:PMT Common shares outstanding 149.9 million Management ownership 25.4% Share price (1) $2.02 Trading volume (2) ~288,000 shares/day Market capitalization $ 303 million Total Net debt (3) (4) $ Net bank debt (3) (4) $ Convertible debentures Senior unsecured notes Enterprise value 310 million (25) million $ 60 million $ 275 million $ 613 million East Edson JV Partner Escrow $ (70) million 1) Five day weighted average 2) Thirty day weighted average 3) As at period end Q2 2014; Proforma East Edson JV and new Senior Notes issuance closed in July 2014 4) Includes $30 million East Edson PMT Escrow funds but excludes JV Partner Escrow Funds BUILT TO GROW BUILT TO PROSPER BUILT TO LAST 5

Operating profile Eastern Alberta Conventional Shallow Gas Mannville Heavy Oil Bitumen Warwick Gas Storage Viking/Colorado Shallow Shale Gas Deep Basin Edson Wilrich Multi-Zone Liquids-Rich Gas Tight Oil and Gas Exploration Actual Production (2014 Estimated Annual Avg) (1) 20,100 boe/d Natural Gas 100 MMcf/d Oil and NGL 3,500 bbl/d P+P Reserves (2) Reserve to Production Ratio (P+P) (RLI) (2) Contingent Resource Bitumen (3) Warwick Storage Working Gas Capacity (gross) (4) (1)19,500 boe/d net of East Edson Royalty (2) As evaluated by McDaniel at May 1, 2014 (3)Best estimate as evaluated by McDaniel (4)30% ownership interest 96.5 MMboe 13 Years 279 MMbbl 21.5 Bcf 6

Diversified portfolio Built to prosper SHALLOW GAS LIQUIDS-RICH GAS HEAVY OIL BITUMEN OTHER Eastern Alberta Conventional Viking / Colorado Shallow Shale Gas Edson Wilrich Greater Edson Multi-zone Edson Secondary Zones Deep Basin Exploration Mannville Mannville EOR Heavy Oil Exploration Panny Bluesky Liege Grosmont & Leduc Other Warwick Gas Storage GOB Technical Solutions Exploration Spectrum of opportunities to invest in through variable commodity cycles 7

Portfolio management strategy CASH FLOW GENERATORS Maximize cash flow Conventional shallow gas Warwick gas storage 26% of 2P reserves 21% of 2P NPV 53% of H1 2014 production PROVEN DIVERSIFYING GROWTH STRATEGIES Invest for growth Eastern Alberta heavy oil Edson liquids-rich gas 74% of 2P reserves 79% of 2P NPV 47% of H1 2014 production MEDIUM AND LONG TERM VALUE STRATEGIES Optimize and Advance Viking/Colorado shale gas Bitumen GOB technical solutions Tight oil & gas exploration Entrepreneurial approach to value creation 8

2014 Top five strategic priorities 1. Grow Edson Liquids-Rich Gas Production, Reserves, Cash Flow, Inventory and Value 2. Maximize Value of Mannville Heavy Oil 3. Maximize Cash Flow from Shallow Gas 4. Reduce Debt and Manage Downside Risk 5. Advance and Broaden Portfolio of High Impact Opportunities with Risk-Managed Investment Strategic priorities focus our activities 9

1. Key Priority Grow Edson liquids-rich gas production, reserves, cash flow, inventory and value 10

Edson Wilrich liquids rich gas To Rosevear Plant (15% WI) Sales Pipeline to Alliance Constructed 2013 Pipeline To Edson Deep Cut Plant 1-34 Gas Plant Capacity 60 MMcf/d 10-3 Gas Plant (2015 Construction) 2 1 16-10 Compressor Capacity 30 MMcf/d 3 6 5 7 3 5 9 8 4 West Edson Type Curve IP 9.0 MMcf/d 9 bbl/mmcf C5+ Reserves 5.6 Bcfe/well 30 (15.0 Net) P+PUDs booked 1 2 4 East Edson NE Type Curve IP 4.6 MMcf/d 25 bbl/mmcf NGL Reserves 2.6 Bcfe/well 58 (48.9 Net) P+PUDs booked East Edson SW Type Curve IP 5.5 MMcf/d 20 bbl/mmcf NGL Reserves 3.4 Bcfe/well 40 (40.0 Net) P+PUDs booked Pre-2013 Horizontal Well 2013 Horizontal Well 2014 Drilled 2014 Q3-Q4 Planned Drill 2015 Proposed Location East Edson JV Lands Inventory of 190 locations / 128 gross (104 net) booked in reserve report Defining optimal spacing through infill well performance may lead to additional inventory

Daily Gas (Mcf/d) Edson Wilrich type curves 20,000 East Edson and West Edson Production 18,000 16,000 14,000 12,000 10,000 East Edson SW Wells (2 Wells) East Edson NE Wells (12 Wells) West Edson Wells (10 Wells) McD East Edson SW Type Curve McD East Edson NE Type Curve West Edson Type Well P+PUD 8,000 6,000 4,000 2,000-0 200 400 600 800 1000 1200 Days on Production Three type curves define reserves and inventory 12

Daily Gas (Mcf/d) Wilrich value potential West Edson 25,000 West Edson Production Projected Economics per Drilling Location 00/01-29-051-18W5/0 (14-29) 00/08-17-051-18W5/2 (04-20) 00/15-34-051-18W5/0 (01-34) Capital (D,C & T) NPV @ 10 % $6.4 MM gross $10.7 MM BT gross 20,000 00/15-35-051-18W5/0 (01-35) 02/16-34-051-18W5/0 (15-26) 03/14-07-051-18W5/0 (09-07) 00/14-19-051-18W5/0 (04-20) ROR F&D Capital Efficiency 168% BT $6.83/boe ~ $8,300 boe/d (first 12 months) 15,000 00/16-21-051-18W5/0 (16-16) 00/16-15-051-18W5/0 (16-16) 00/01-15-051-18W5/0 (16-03) West Edson Average Payout Recycle Ratio 3.7 0.8 Years Assumptions (McDaniel April 2014) 10,000 PMT West Edson Type Curve McD West Edson Type Curve 2014 Pricing $3.60/GJ; $79.90/bbl NGL Operating Costs $1.62/boe (first year) 5,000 Well Depth Type Curve 2P Reserves 4,200M HZ; 2,700M TVD IP 9 MMcf/d 1 year exit rate 2.6 MMcf/d 9 bbl/mmcf C5+ 5.6 Bcfe sales per well - 0 100 200 300 400 500 600 700 Days on Production Royalties Inventory of 36 net locations at 2 wells per section Gross Locations 5% royalty until NGDDP credit of ~$3.5 MM is recovered 30 Proved and Probable Undeveloped 42 Additional Prospect Inventory Monitoring infill well performance to evaluate locations at increased drill density 13

East Edson JV type curve economics Projected Economics per South West Drilling Location Projected Economics per North East Drilling Location Capital (D,C & T) $ 5.1 MM Capital (D,C & T) $ 5.0 MM NPV @ 10 % $ 5.3 MM NPV @ 10 % $ 3.4 MM ROR 50 % BT ROR 42 % BT F&D $9.16 / boe F&D $11.63 / boe Capital Efficiency $10,650 boe/d (first twelve months) Capital Efficiency $14,269 boe/d (first twelve months) Payout 1.7 Years Payout 2.3 Years Recycle Ratio 3.2 Assumptions (McDaniel April 2014) 2014 Price $ 4.76 / Mcf; $ 101.56 / bbl Condensate Recycle Ratio 2.5 Assumptions (McDaniel April 2014) 2014 Price $ 4.88 / Mcf; $ 101.56 / bbl Condensate Operating Costs $2.70 / boe (first year) Operating Costs $4.39 / boe (first year) Well Depth 4,350 M HZ; 2,500 TVD Well Depth 4,250 M HZ; 2,400 TVD Type Curve IP 5.5 MMcf/d 1 year exit rate 1.6 MMcf/d 20 bbl/mmcf sales NGL/condensate Type Curve IP 4.6 MMcf/d 1 year exit rate 1.1 MMcf/d 34 bbl/mmcf sales NGL/condensate 2P Reserves 3.4 Bcfe per well 2P Reserves 2.6 Bcfe per well Royalties 5% royalty until NGDDP credit of ~$3.1 MM is recovered Royalties 5% royalty until NGDDP credit of ~$2.8 MM is recovered Gross Locations 40 Proved and probable Undeveloped 20 Additional Prospect Inventory Gross Locations 58 Proved and probable Undeveloped 98 gross (89 net) locations identified within the McDaniel report for East Edson 14

East Edson JV transaction details Granted two royalties that work in combination to create a fixed, first-out wedge production GORR Flat ~ 5.6 MMcf/d plus associated liquids of ~150 bbl/d until 2022 Declining at 10% per year from Jan 2023 through December 2034 Producing Royalty Sale of 50% GORR on current production Proceeds = $50 million $30 million in PMT escrow Drilling Royalty Farm-out of Undeveloped Wilrich for $70 million Earned and contributed to escrow at July closing Perpetual Commitments Drill ~13 wells with $ 70 million of farm out capital by March 31, 2015 Drill additional ~6 wells with $30 million of Producing Royalty sale proceeds prior to December 2015 Construct 30 MMcf/d gas plant for September 1, 2015 onstream date (~$30 million) Drill an additional ~6 wells for $30 million prior to December 31, 2022 Generating $40 to $50 million/year of free funds flow by 2016 15

East Edson JV transaction rationale Facilitates significant production and cash flow growth East Edson property becomes self-funding with kick start of capital to grow production Capital infusion allows for technically recognized reserves to become eligible for NI 51-101 booking based on defined capital funding profile Increases reserve-based NAV by 56% Transaction metrics are significantly accretive to Perpetual s current valuation PMT East Edson Cash Flow Multiple 2.8 X 8.0 X D ec 3 1, $ per Flowing boe $33,000 $105,000 Transaction does not impinge on Perpetual s base capital program Fully prepared to execute scaled up activity Perpetual maintains full operational control of the East Edson Property Facilities expansion plan optimized to maximize efficiencies Cost savings by operating all East Edson Facilities at their optimum capacity Materially improves debt to funds flow ratio by year end 2015 to 2.7:1 (trailing 12 months) Capital injection kick starts East Edson development for growth 16

Boe/d Cumulative Production (MBoe) Greater Edson liquids-rich gas play performance 12,000 14,000 40% net production growth in 2014 10,000 8,000 6,000 4,000 12,000 10,000 8,000 6,000 4,000 Driven by West Edson capacity expansion Flat production forecast at Edson Production growth from JV drilling offset by sale of 50% GORR on developed lands East Edson to drive growth in 2015 Drill to fill West Edson capacity of 30 MMcf/d net Drill to fill existing East Edson facilities through 16-10 compressor Construct new 30 MMcf/d East Edson plant and bring online in September 2015 and drill to maintain at capacity 2,000 2,000-2009 2010 2011 2012 2013 2014E2015E - Edson West Edson Liquids-rich gas growth area built from 0 to 11,000 boe/d in 5 years Infrastructure and inventory in place for continued growth 17

2. Key Priority Maximize value of Mannville heavy oil 18

Eastern Alberta Conventional heavy oil Discovered 14 Mannville pools 8 Lloyd, 5 Sparky, 1 Basal Quartz > 200 MMbbl Original Oil in Place > 10 MMbbl @ 5% recovery factor Current Production ~ 2.750bbl/d Low cost HZ development $1.1 MM single lateral HZ well $1.4 MM for multi-lateral HZ well Average initial rate ~80 bbl/d 2014 H1 Capital Activity 11 gross (10 net) infill wells 2 (1.7 net) new pool tests successful 2014 H2 Capital Plan 7 gross (6.1 net) wells Waterflood Implementation in I2I Pool Water support injection conversions in 2-3 additional pools Planning for 2015 EOR Pilot H1 2014 Development H1 2014 New Pool Tests H2 2014 Drilling New pool tests designed to add 20+ drill ready development locations 19

Mannville heavy oil value potential Projected Economics Per Well Lloyd Sparky Capital (D,C & T) $1.2 MM $1.2 MM NPV @ 10 % $1.6 MM $0.8 MM ROR ~ 200% ~ 95% F&D $13.50 / Boe $20.50 / Boe Payout 0.7 Year 1.2 Year Capital Efficiency ~$15,000/Boe/d ~$25,000/Boe/d Recycle Ratio 3.0 2.7 2014 Pricing Operating Costs Average Well 2P Reserves Royalties Assumptions (McDaniel Year End 2013) $68.90/bbl Wellhead heavy price WTI $US95/bbl, WCS $US23.5/bbl, offset $7.60/bbl $6.23/Boe (first year) & $12.60/Boe (lifetime) Lloyd IP 120 bbl/d to 75 bbl/d after year 1 Sparky IP 85 bbl/d to 44 bbl/d after year 1 90 Mbbl per Lloyd well 60 Mbbl per Sparky well 5% for first 18 months on Crown; variable on Freehold Oil over shakers while drilling Sparky development pad HZ pad site Highly profitable at current oil prices 20

Gross Oil Production m3/d Waterflood and enhanced oil recovery Mannville I2I Waterflood Pilot Pool Sparky Mid Type Log 100/09-32-050-08W4/00 > 24 % DENSITY POROSITY 6 m OIL PAY Sparky Mid Sand Working Interest 66.7% OOIP: 53 MMbbl Cum Prod n + McDaniel P+P: 1.7 MMbbl (3.1% recovery) 17 Horizontals to date (100 m spacing) 3 wells drilled in H1 2014 Implementing Waterflood 5 injector conversions in 2014 Reservoir simulation and lab work for polymer flood underway 200 Sparky I2I Pool Primary Production vs. Waterflood Case 1- Develop. (NO WF) - Oil Prod. (m3/d) Case 2- Develop. and WF - Oil Prod. (m3/d) 100 0 Jan-14 Jan-19 Jan-24 Jan-29 Waterflood value created through reduction in primary production decline 21

Waterflood and enhanced oil recovery scope Select Pools OOIP (MMbbl) Cumulative production to YE 2013 (MMbbl) P+P Reserves booked at YE 2013 (MMbbl) Implied Recovery Factor (%) Expected Primary Recovery (5-8% (MMbbl) Potential with Secondary Recovery and EOR (10-15%) (MMbbl) Sparky I2I (2) 53 0.5 1.2 3.1% 2.7 4.2 5.3 8.0 Upper Mannville A 30 0.5 0.6 3.7% 1.5 2.4 3.0 4.4 Upper Mannville B 14 0.2 0.4 4.5% 0.7 1.1 1.4 2.1 Total 97 1.2 2.2 3.5% 4.8 7.7 9.7-14.5 6.5 X Large scope for increased reserves and value through waterfloods and possible polymer floods 22

Operating Cash Flow ($MM) Cumulative Cash Flow ($MM) Production (Boe/d) Cumulative Production (MBoe) Capital ($MM) Cumulative Capital ($MM) Mannville heavy oil play performance $60 $180 $50 $40 $30 $20 $10 $0 4,000 3,500 3,000 2,500 2,000 1,500 1,000 500-2009 2010 2011 2012 2013 2014E 2009 2010 2011 2012 2013 2014E $130 $80 $30 -$20 4,500 4,000 3,500 3,000 2,500 2,000 1,500 1,000 500 - Transitioning from growth to sustaining production in 2014 Drilling capital reduced Investing in facilities for waterflood Significant value to be created through waterflood & EOR $90 $80 $70 $60 $50 $40 $30 $20 $10 $0 2009 2010 2011 2012 2013 2014E $200 $150 $100 $50 $0 Evaluating waterflood performance on I2I Injection to start pressure maintenance in 2-3 other pools Scoping polymer flood costs and potential Heavy oil portfolio built from 0 to over 3,000 boe/d in 3 years Investment recovered with cash flow now exceeding future capital spending 23

3. Key Priority Maximize cash flow from shallow gas 24

Conventional shallow gas East Central and Northeast Alberta Cretaceous and Devonian sweet shallow gas Belly River Viking Grand Rapids Lower Mannville Pre Cretaceous Unconformity Current production: ~ 60-65 MMcf/d Base declines < 15% Multiple stacked zones and play types Extensive plant and pipeline infrastructure with large fixed cost component Low base royalty rate Average 5% at <$5/Mcf 740 uphole recompletions awaiting depletion of producing zones Low cost production and reserves adds (<$10,000/boe/d; <$1.00/Mcf) Focused on fixed operating cost reductions Metering, municipal taxes Netbacks highly leveraged to gas prices Production additions of 6.2 MMcf/d (IP30) with high capital efficiencies of <$5,000 boe/d in Q1 Repeating in South in Q3 25

4. Key priority Reduce debt and manage downside risk 26

Debt reduction $100 Million Target Set in November 2013 Closed 2014 West Central AB undeveloped land Gas over Bitumen Monetization $3 million $20.5 million D ec 3 1, 2014 Dispositions $73.5 MM East Edson JV Net Proceeds $120 million Producing Royalty sale $50 million Drilling Royalty Farm-in $70 million 2014 Year to Date Total Disposition Proceeds JV Cash on Hand Total Proceeds $73.5 million $70 million $143.5 million Proceeds for Debt Reduction Proceeds Dedicated to JV Spending Targeting another $60 million in asset sales for liquidity and further debt reduction $43.5 million $100 million 27

Balance sheet Net Bank Debt: $(25) million Borrowing base on credit facility - $100 million post new Senior Notes issuance Next semi-annual redetermination - October 2014 $30 million of restricted cash in escrow (partial proceeds of East Edson Producing Royalty sale) Senior Unsecured Notes: $275 million 7 year Notes issued March 2011 Coupon rate - 8.75%; Maturity date - March 2018 New $125 million 5 year Notes issue closed in July 2014 Coupon rate - 8.75%; Maturity date - July 2019 Convertible Debentures: $60 million Repayable in cash or equity at Perpetual s discretion at par on or after December 31, 2014 TSX Symbol Amount Outstanding Coupon Rate Conversion Price Maturity Date 5 Day Weighted Avg. Trading Price REPAID AUGUST 26, 2014 PMT.DB.D $99.9 million 7.25% $7.50 January 31, 2015 $100.50 PMT.DB.E $59.9 million 7.00% $7.00 December 31, 2015 $100.54 JV Partner Escrow Funds: ($70) million JV Partner funding from Drilling Royalty committed to fund East Edson farm-in activity Expected to spend vast majority of escrow funds by December 31, 2014 Total Net Debt: $310 million ($240 million Net of East Edson JV Cash on Hand) At June 30 th - Proforma East Edson JV and Senior Notes Issuance Over 85% of debt has term into 2018 28

2014 Capital spending Total Capital: $172 million $65 to 70 million of capital spending will be funded by JV Partner escrow account and not reported by Perpetual H1 2014 Wells Capital H2 2014 Wells Capital Wells Total Capital West Central Liquids-Rich Gas (1) 4 gross (2.5 net) $26 MM 9 gross (4.5 net) $28 MM 13 gross (7.0 net) $ 54 MM East Edson JV (2) - - 13 gross (13.0 net) $ 81 MM 13 gross (13.0 net) $ 81 MM Mannville Heavy Oil (3) 13 gross (11.7 net) $14 MM 7 gross (6.1 net) $15 MM 20 gross (17.8 net) $ 29 MM Eastern Shallow Gas and Other Recompletions/ Workovers/ Optimization $4 MM $4 MM $8 MM Total $44 MM $128 MM $ 172 MM 1) Includes east and West Edson drilling in H1 and facility capital to expand West Edson to 60 MMcf/d gross (50% WI) 2) Funded with $70 MM of East Edson JV Cash on Hand and $30 MM of Perpetual escrowed funds and including portion of facility capital for equipment for 30 MMcf/d East Edson plant to be constructed in 2015 3) Includes $3 MM of expanded waterflood capital 2014 Capital focused on proven diversifying plays 29

WTI (US$/BBL) 2014 funds flow 2014 Capital spending of $172 million $107 million reported net to Perpetual Production of 20,100 boe/d (19,500 boe/d net of East Edson JV Royalty) 2014 Funds Flow AECO ($/GJ) 3.50 4.00 4.50 5.00 5.50 85 76 80 83 87 90 95 79 83 86 90 93 100 80 84 87 91 94 105 80 84 87 91 94 115 81 85 88 92 95 1) 2014 settled and forward prices for July through December at Sept 10, 2014 were $4.04/GJ at AECO and US $93.31/bbl WTI 2014 funds flow estimated at ~$80 to 90 million at current commodity prices 30

WTI (US$/BBL) 2015 funds flow 2015 Capital spending of $120 million Production of 24,500 boe/d (23,400 boe/d net of East Edson JV Royalty) 2015 Funds Flow AECO ($/GJ) 3.50 4.00 4.50 5.00 5.50 85 87 108 129 151 172 90 93 114 135 157 178 95 100 121 143 164 185 100 105 126 148 170 191 105 110 132 154 175 196 110 113 135 157 175 199 1) 2015 settled and forward prices at Sept 10, 2014 were $3.97/GJ at AECO and US $89.84/bbl WTI 2015 funds flow estimated at ~$120 million at current forward strip prices 31

Projected balance sheet reconciliation Q2 2014 Capitalization July-August 2014 Transactions H2 2014 Operations (projected) 2015 Operations (projected) Sources Sources Sources East Edson JV GORR sale/farmout $120 Funds Flow (projected) $42 Funds Flow (projected) $120 Issue of Senior Unsecured Notes $125 Withdrawal of East Edson escrow $67 Withdrawal of East Edson escrow $33 Increase in bank debt $22 Increase in bank debt $24 $245 $131 $177 Uses Uses Uses East Edson JV escrows $100 East Edson Escrow Capex $70 East Edson Escrow Capex $30 Redeem convertible debentures D $100 Other Capex $61 Other Capex $87 Reduction in net bank debt $45 Repay convertible debentures E $60 $245 $131 $177 Period-end Capitalization Q2 Period-end Capitalization Period-end Capitalization Period-end Capitalization Net bank debt $50 Net bank debt $5 Net bank debt $27 Net bank debt $51 Senior unsecured notes $150 Senior unsecured notes $275 Senior unsecured notes $275 Senior unsecured notes $275 Convertible debentures $160 Convertible debentures $60 Convertible debentures $60 Convertible debentures - Perpetual Funds in Escrow ($30) Perpetual Funds in Escrow ($25) Perpetual Funds in Escrow - $360 $310 $337 $326 Liquidity Bank Borrowing Base $120 Bank Borrowing Base $100 Bank Borrowing Base (projected) $130 Bank Borrowing Base (projected) $150 Undrawn Credit Capacity Undrawn Credit Capacity Undrawn Credit Capacity Undrawn Credit Capacity (including escrow) $70 (including escrow) $195 (including escrow) $133 (including escrow) $99 (1) Assumes H2 2014 and 2015 commodity prices as per forward market as at Sept 2, 2014 (2) Assumes recovery of sunk costs and first well spending on East Edson JV activity from Perpetual Escrow Funds (3) Includes $11 million long term Crown receivable for GOB financial solution at March 31, 2014; Reduces to $0 by Dec 31, 2015 (4) Debt estimates are period end (5) YE 2015 assumes repayment of PMT.DB.E in cash from credit facility Borrowing capacity expected to be available to redeem PMT.DB.E with cash prior to December 2015 32

5. Key Priority Advance and broaden portfolio of high impact opportunities with risk-managed investment Viking/Colorado Shallow Shale Gas Bitumen Exploration 33

Viking/Colorado shallow shale gas Belly River Play Fairway Cardium/ Colorado Wells Perpetual Lands Viking Proved Undeveloped Viking Probable Undeveloped Viking Proven Non-Producing Prospect Inventory 5 Yr Viking Booked reserves 12 Bcf PNP booked in recompletions Historical 2P reserves of 100+ Bcf removed from bookings due to price revisions and lack of activity Gas price recovery and capital commitment could drive substantial future bookings Colorado > 1 TCF potential recoverable resource Average 435 MMcf / well gross Expected HZ development at 8+ wells / section Over 1,200 net sections of land with Viking/Colorado potential Extensive plant and pipeline infrastructure Develop Colorado Group shales with tight Viking and Mannville sands to reduce costs and enhance economics 34

Colorado technical advancement Colorado group free gas in place Total Resource in Place > 130 Tcf OGIP estimated to average 16 Bcf/section Proven recovery from Cardium equivalent Potential in up to 6 zones within 300m shale 2012-2013 Advanced detailed (3G) technical study Gas in Place, brittleness mapping, production inflow and fracture modeling Evaluated induced fracturing recompletions 2014 Monitor industry horizontal drilling programs Plan and execute technology optimization program through: Recompletions Vertical wells Horizontal drilling Frac designs Small third party drilling commitment 2015 2016 Advance to full scale development to fill existing infrastructure as economics warrant Evaluating frac design, costs & performance for full scale development Extensive inventory and infrastructure to fuel growth in 2016 and beyond 35

Bitumen 527 net sections (329,000 net acres) of oil sand leases Various formation targets and ultimate recovery methods 7 potential project areas with varying potential Over 3 billion bbls OBIP independently recognized at Liege and Panny 278 MMbbl contingent resource 467 MMbbl additional prospective resource Perpetual OS Leases Primary Projects SAGD Projects Fireflood Projects CSS Projects Electric Heaters Oil Pipelines 36

Bitumen Panny Bluesky 8 m Bitumen 10 m Bitumen Low rate cold flow without solvent or thermal assistance Average pay thickness 11 m Low viscosity bitumen ~15,000 cp @ 25 o C 50,000 cp at 11 o C reservoir temp Highly mobile at ~70 o C Panny Bluesky Resource Assessment (McDaniel P50) 755 MMbbl Discovered OBIP 132 MMbbl Contingent Resource 17.5% recovery factor applied utilizing horizontal cyclic steam Vertical Wells Existing Horizontal Well Roads Natural Gas Pipeline Oil Well Effluent Pipeline Perpetual Gas Plant Perpetual Oil Sands Rights Other Perpetual Lands Excellent reservoir quality in Bluesky homogeneous shoreface sand facies Resource to support >15,000 bbl/d commercial project for 20 to 25 years LEAD Technology pilot pending Electric heat with water &/or solvent ERCB application approved IETP funding approved 37

LEAD process technology pilot Low pressure electro-thermally assisted drive First stage of pilot planned for 2015 $5 million expected capital net of 30% IETP funding Evaluating heater technology and validating reservoir model Second stage of pilot an additional $20 to $30 million Guided by first stage learnings 2017 start-up Initial 10,000 to 15,000 bbl/d development by 2019 if pilot successful Drilling-intensive technology allows for scalability without large upfront capital commitment of steam projects Modelled recovery factor is >50%, encouraging increasing scope for commercial project Pilot Project Configuration Top Gas Oil Heaters / Injectors Producer Electrical heating cable with water injection for mobility and pressure support 38

Bitumen Liege carbonates AOC Shell Excellent reservoir quality vuggy porosity in Grosmont Husky Laricina / Osum 3 Grosmont carbonate / Leduc OV wells drilled Combined with legacy gas wells to evaluate and map resource Stacking of 3 Grosmont units > 30 m pay Leduc reef facies also present and bitumen saturated in places; geologically complex Resource Assessment (McDaniel best estimate) 2,327 MMbbl bitumen in place (Undiscovered plus discovered) 132 MMbbl Contingent Resource assigned 449 MMbbl Prospective Resource assigned 25% recovery factor applied using SAGD as technology under development 39

Investment Thesis

Strong annual growth forecast 2014 Key diversifying plays production growth of ~22% Growth focused at West Edson Funds flow and funds flow per share growth of >50% Disposition program targeting $100 million in debt reduction Monetized $73.5 million of assets Generated $70 million in additional capital funding through farm-in 2015 Gas and NGL projected production growth >20% Mannville heavy oil infill drilling and waterfloods to sustain production and grow funds flow Backfill conventional shallow gas declines with high capital efficiency workovers Forecast funds flow growth of 35-40% Projected YE2015 debt to TTM cash flow ratio of 2.7 Highly leveraged to natural gas prices Every $0.50/GJ increase in gas price translates into $20-$25 million increase in funds flow Robust commodity prices could bring debt to cash flow ratio below 2 times Year over year growth forecast on top priorities 41

Proved and Probable Mboe % Diversifying Assets Reserve distribution 120,000 80% 100,000 70% 60% 80,000 50% 60,000 40% 40,000 30% 20% 20,000 10% - 2009 2010 2011 2012 2013 2014Q2 2014E 0% Shallow Gas Mannville Heavy Oil Other Deep Basin Elmworth West Edson East Edson % of Diversifiying Assets 1) 2014 Q2 at May 1, 2014 giving effect to East Edson JV McDaniel Report Reserve growth in higher value diversifying assets 42

Sum of the parts NAV Per Share (1) WGS LP valued at prorata 2013 buyback acquisition $28 million (2) McDaniel April 2014 Assumptions Trading at <half of reserve-based net asset value 43

Future growth and value creation 2016-2020 LIQUIDS-RICH GAS SHALLOW GAS HEAVY OIL BITUMEN OTHER Edson expansion for additional inventory development West and/or East Edson additional downspacing Development of secondary targets including Belly River, Cardium, Second White Specks, Viking, Notikewin, Fahler, Rock Creek, Blueridge & Duvernay Deep Basin Exploration Waskahigan Duvernay, Columbia Fahler & Cardium, Other Optimize conventional assets with high capital efficiency production adds Viking/Colorado growth to backfill shallow gas declines Colorado full scale development for growth to fully utilize extensive infrastructure network and increase operating netbacks Mannville waterflood expansion Mannville polymer flood implementation New pool exploration Panny bitumen pilot and phase 1 commercial development Marten Hill pilot Liege carbonate Warwick Gas Storage delta pressuring Other Exploration Longer term plans in motion for future growth through diversified portfolio 44

Illustrative Production Future production growth potential Inventory captured and risk assessment on track for future production growth Growth trajectory depends on commodity prices, capital and play performance 45

Key investment highlights Asset base repositioning for resource-style & diversification successful Mannville heavy oil delivering strong cash flow with material secondary recovery growth potential Edson Wilrich liquids-rich gas inventory proven and highly economic Execution and operational excellence in chosen strategies Increasing high netback production in asset mix growing funds flow 80% of debt has term into 2018 Asset dispositions and growing cash flow materially improved debt to cash flow ratios Multiple levers available to manage balance sheet and PMT.DB.E convertible debenture maturity in 2015 Pursuing further asset dispositions to continue to reduce outright debt leverage Capital liquidity available to execute growth paths Trading significantly below Reserve-Based Net Asset Value High impact value potential from medium to long term assets Tremendous leverage to any gas price cycle recovery in 2015 and beyond Spectrum of opportunity to grow and prosper 46

FOR ADDITIONAL INFORMATION Susan L. Riddell Rose President & CEO Additional Information Cameron R. Sebastian Vice President, Finance & CFO 3200, 605 5 Avenue SW Calgary, Alberta Canada T2P 3H5 800.811.5522 TOLL FREE 403.269.4400 PHONE 403.269.4444 FAX info@perpetualenergy.com EMAIL WWW.PERPETUALENERGYINC.COM

Important information about the presentation Non-GAAP Measures This presentation contains financial measures that may not be calculated in accordance with generally accepted accounting principles ("GAAP"). Readers are referred to advisories and further discussion on non-gaap measures contained in the "Non-GAAP Measures" section of our most recent management's discussion and analysis. IP rates Initial production or IP rates contained in this presentation are based the length of the specific production tests disclosed herein and are not necessarily indicative of long-term performance or ultimate recovery. Initial production rates disclosed herein are based on 3 days of initial production and are not necessarily indicative of long-term performance or ultimate recovery. Financial Outlooks Included in this presentation are estimates of Perpetual's future cash flow and debt levels, which are based on the various assumptions as to production levels, capital expenditures, commodity prices and other assumptions disclosed in this presentation. To the extent such estimates constitute a financial outlook, they were approved by management of Perpetual in July 2014 and are included to provide readers with an understanding of Perpetual's anticipated financial position and readers are cautioned that the information may not be appropriate for other purposes. Reserves, Resource and F&D Disclosure Unless as otherwise noted, reserves and resource information included in this presentation is based on independent evaluations prepared by McDaniel and Associates Consultants Ltd. in accordance with National Instrument 51-101 ("NI 51-101") using McDaniel's forecast prices and costs. All of Perpetual's contingent resources currently have an "undetermined" economic status as sub-classification into economic and uneconomic categories has not been evaluated. Contingencies affecting the classification of the resources include corporate development plans, the need for regulatory approval, and the need to perform an economic study regarding production. There is no certainty that it will be commercially viable to produce any portion of the resources. Please refer to "Notes Pertaining to the Reporting of Bitumen Contingent Resource" in Perpetual's Annual Information Form dated March 7, 2014 for applicable definitions and risk factors pertaining to Perpetual's reserve and resource disclosure. Perpetual's F&D costs are disclosed under the heading "Finding and Development Costs" in Perpetual's February 4, 2014 press release. Please refer to this press release for additional disclosure pertaining to Perpetual's F&D costs. The aggregate of exploration and development costs incurred in the most recent financial year and the change in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year. Projected Economics This presentation includes estimates of projected economics or value potential for Perpetual's Mannville heavy oil and West Edson Wilrich liquids rich gas assets. Estimates of "projected capital", "NPV@8 and 10%", "ROR", "F&D", "capital efficiency" and "recycle ratio" are provided in respect of these assets. These terms referenced in this presentation are estimates by Perpetual of future results based on the indicated assumptions and are by their nature projections which are different than terms calculated in accordance with NI 51-101, which are historical calculations. These estimates have been provided as Perpetual believes they provide a reasonable estimate of the future economics of Perpetual's Mannville heavy oil and West Edson Wilrich liquids rich gas value. These terms do not have a standardized meaning prescribed by NI 51-101, the COGE Handbook or CSA Notice 51-324 and therefore these measures, as defined by Perpetual, may not be comparable to similar measures presented by other issuers. These estimate constitute forward-looking information and therefore reflects several material factors, expectations and assumptions and is subject to a number of risk factors. See "Forward-Looking Information" above for further information. Mcf equivalent (Mcfe) Mcf equivalent (Mcfe) may be misleading, particularly if used in isolation. In accordance with NI 51-101 a Mcfe conversion ratio for oil of 1 Bbl: 6 Mcf has been used, which is based on an energy equivalency conversion method primarily applicable at the burner tip and does not necessarily represent a value equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. Net Asset Value In relation to the disclosure of net asset value ("NAV") in this presentation, the NAV presented herein is what is normally referred to as a "produce-out" NAV calculation under which the current value of Perpetual's reserves would be produced at forecast future prices and costs and do not necessarily represent a "going concern" value of our company. The value is a snapshot in time and is based on various assumptions including commodity prices and foreign exchange rates that vary over time. It should not be assumed that the NAV represents the fair market value of Perpetual. 48

Appendix

Diversification Warwick Gas Storage 40 Bcf Storage Reservoir Delta Pressure to 47 Bcf 10 Bcf base reserves cushion gas in place Up to 25 Bcf potential working gas capacity 1.2 to 1.5 cycle facility WGSI Leases Well Site Pad Storage Facility Pipeline Horizontal Wells 2012 Hz Wells TCPL Pipeline Commercial Park and Loan business 30 to 50 year life Grass Roots Development Existing depleted gas pool Facility Construction 2010 19-21.5 Bcf working gas capacity Expansion Potential Delta pressuring to increase working gas to 24.5 Bcf with minimal incremental costs 30% Perpetual Interest Manage WGS LP for annual fee Diversified Cash Flow 2012 & 2013 ~$11 million/year gross Non-depleting, long life, diversifying asset Cash flow growth potential when spreads normalize to historical levels 50

Hedging Gains ($ millions) Commodity price risk management strategy Enhance or protect funds flow and balance sheet Enhance or protect the economics of an acquisition Enhance or protect capital program economics Capitalize on perceived market anomalies $200 $150 $100 $50 $0 2009 2010 2011 2012 2013 Hedging Gain Options Premium Gas price risk management positions in place mainly for 2014 More volume and length to oil price hedges 51