Offering of Senior Unsecured Notes. Susan Riddell Rose President and CEO Cam Sebastian VP Finance and CFO

Transcription

1 Offering of Senior Unsecured Notes Susan Riddell Rose President and CEO Cam Sebastian VP Finance and CFO

2 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 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

3 Summary Terms of Offering Issuer Perpetual Energy Inc. Amount $100MM Currency CAD Maturity 5 years Rank Senior Unsecured Guarantees All material wholly-owned subsidiaries Optional Redemption NC2 Change of Control Put at 101% Use of Proceeds Distribution Repay 7.25% Subordinated Convertible Debentures due January 31, 2015 and general corporate purposes Canada Private Placement U.S. 144A Timing Pricing expected on July 18, 2014 Expected Ratings Moody s: [Caa1 (stable outlook);] S&P: [Corporate: B- (stable outlook); Senior Notes: CCC+] Joint Bookrunners Scotia Capital Inc., BMO Nesbitt Burns Inc., CIBC World Markets Inc. 3

4 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 Recent East Edson JV transaction accelerates growth trajectory Execution and operational excellence in chosen strategies Increasing high netback production in asset mix growing funds flow 75% of debt will have term into 2018 providing flexibility Asset dispositions and growing cash flow improving debt to cash flow ratios Multiple levers available to manage balance sheet and PMT.BD.E convertible debenture maturity in 2015 Pursuing further asset dispositions to continue to reduce outright debt leverage High impact value potential from medium to long term assets Tremendous leverage to any gas price cycle recovery in 2015 and beyond Trading significantly below Reserve-Based Net Asset Value Spectrum of opportunity to grow and prosper 4

5 Company Overview

6 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 6

7 52% OF PRODUCTION >59% OF RESERVES 62% OF REVENUE >70% OF RESERVE VALUE

8 Perpetual Energy TSX:PMT Common shares outstanding million Management ownership 25.4% Share price (1) $2.09 Trading volume (2) ~270,000 shares/day Market capitalization $ 312 million Net debt (3) Net bank debt (4) Convertible debentures Senior unsecured notes East Edson JV Committed Funds Enterprise value 1) Five day weighted average 2) Thirty day weighted average 3) Net of East Edson JV Cash on Hand 4) Estimate effective May 1, 2014; Proforma East Edson JV and GOB Monetization $ 258 million $ 18 million $ 160 million $ 150 million $ (70) million $ 570 million BUILT TO GROW BUILT TO PROSPER BUILT TO LAST 8

9 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) Natural Gas Oil and NGL P+P Reserves (2) Reserve to Production Ratio (P+P) (RLI) (2) Contingent Resource Bitumen (3) Warwick Gas Storage Working Gas Capacity (gross) (4) 19,500 Boe/d 97 MMcf/d 3,500 bbl/d 96.5 MMboe 13 Years 279 MMbbl 21.5 Bcf (1)Net of East Edson JV GORR Production (2)As evaluated by McDaniel at May 1, 2014 proforma pending transactions (3)Best estimate as evaluated by McDaniel (4)30% ownership interest 9

10 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 Deep Basin Exploration Mannville Mannville EOR Heavy Oil Exploration Panny Bluesky Liege Grosmont & Leduc Marten Hills Clearwater Warwick Gas Storage GOB Technical Solutions Exploration Other Spectrum of opportunities to invest in through variable commodity cycles 10

11 Portfolio management strategy CASH FLOW GENERATORS PROVEN DIVERSIFYING GROWTH STRATEGIES MEDIUM AND LONG TERM VALUE STRATEGIES Maximize cash flow Conventional shallow gas Warwick gas storage 26% of 2P reserves 49% of Q production Invest for growth Eastern Alberta heavy oil Edson liquids-rich gas 74% of 2P reserves 51% of Q production Optimize and Advance Viking/Colorado shale gas Bitumen GOB technical solutions Tight oil & gas exploration Entrepreneurial approach to value creation 11

12 Production by Core Area Three months ended March 31, Natural Gas (MMcf/d) Eastern - North Eastern South West Central Total natural gas Crude Oil (bbl/d) Eastern North 5 3 Eastern South 2,861 2,754 West Central Total crude oil 2,911 2,786 NGL (bbl/d) Eastern North - - Eastern South 11 7 West Central Total NGL Total actual production (boe/d) 18,794 18,244 Gas Over Bitumen Deemed Production (MMcf/d) Total actual plus deemed production (boe/d) 22,036 22,403 12

13 2014 Top five strategic priorities 1. Reduce Debt and Manage Downside Risk 2. Grow Edson Liquids-Rich Gas Production, Reserves, Cash Flow, Inventory and Value 3. Maximize Value of Mannville Heavy Oil 4. Maximize Cash Flow from Shallow Gas 5. Advance and Broaden Portfolio of High Impact Opportunities with Risk-Managed Investment Strategic priorities focus our activities 13

14 1. Key priority Reduce debt and manage downside risk 14

15 Debt reduction $100 Million Target Set in November 2013 Closed 2014 West Central AB undeveloped land $3 million Gas over Bitumen Monetization $20.5 million East Edson JV Net Proceeds $120 million D ec 3 1, 2014 Dispositions $73.5 MM 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 Targeting another $60 million in asset sales for liquidity and further debt reduction 15

16 East Edson JV transaction details Sale of a 50 percent royalty interest on current production (Producing Royalty) Proceeds: $50 million Gross 50 percent royalty on existing production, less deductions for transportation Initially ~ 6.2 MMcf/d plus associated oil and NGLs Farm-out of Undeveloped Wilrich for Drilling Royalty $70 million of JV partner funds contributed for development of East Edson Property Two Royalties work in combination Drilling Royalty equates to 5.6 MMcf/d plus associated NGL s minus Producing Royalty Gross royalty on gas and associated NGL revenue less transportation Perpetual Commitments Perpetual also commits $30 million of proceeds from Producing Royalty sale proceeds for drilling at East Edson Property Perpetual will construct a 30 MMcf/d gas plant at an estimated cost of $28 to 30 million; September 1, 2015 onstream date Perpetual will spend a further $30 million to develop the East Edson Property prior to December 31, 2022 Effectively $120 million gross proceeds 16

17 East Edson JV production profile D ec 3 1, Fixed First-out Wedge Production GORR 5.6 MMcf/d plus associated liquids until 2022 Declining at 10% per year from Jan 2023 through December % gas / 15% NGLs (~43% C5+) Production buffer above GORR generated through funded Wilrich development 17

18 East Edson JV transaction rationale Significant cash flow growth Capital infusion allows for technically recognized reserves to become eligible for NI booking based on defined capital funding profile Increases Reserve-based NAV by 56% Transaction metrics are significantly accretive to Perpetual s current valuation: D ec 3 1, PMT East Edson Cash Flow Multiple 2.8x 8.0x $ per Flowing boe $33,000 $105,000 The transaction does not impinge on Perpetual s base capital program allowing for execution of previously planned activities while also allowing for acceleration of the development of the East Edson Property Perpetual maintains full operational control of the East Edson Property The facilities expansion plan has been optimized to provide maximum efficiencies and cost savings by operating all East Edson Facilities at their optimum capacity Capital injection kick starts East Edson development 18

19 Gas over Bitumen Monetization Gas over Bitumen Monetization for proceeds of $20.5 million Payment monthly equal to Crown royalty credit earned on GOB financial solution for shut-in Legend property 0.5 x [(Shut-in Deemed Production of 10.7 MMcf/d) x 0.8) x (Alberta Reference Price- $0.3791/GJ)] Retain 35% revenue related to any excess of the Alberta Gas Reference Price over the independent reserve evaluators January 1, 2014 natural gas price forecast $19 million of proceeds at closing reflecting January 1, 2014 effective date and adjustments Remaining GOB royalty credits terminated July 1, 2014 upon expiry of 10 year term $12.2 million outstanding Crown receivable still to be collected against future Crown royalties otherwise payable Closed June 26,

20 Balance sheet Net Bank Debt: $29 million Borrowing base on credit facility $120 million ($100 million pro forma Notes issuance) Next semi-annual redetermination October 2014 $30 million of funds restricted for 2015 Perpetual East Edson Commitment JV Cash on Hand: ($100 million) Committed to Fund East Edson Farm-in Activity Expected to be spent by December 31, 2014 Senior Unsecured Notes: $150 million Coupon rate % Maturity date - March 2018 Convertible Debentures: $160 million Repayable in cash or equity at Perpetual s discretion 2015 maturities Senior notes provisions will not restrict cash repayment TSX Symbol Amount Outstanding Coupon Rate Conversion Price Maturity Date Total Net Debt: $239 million (Net of East Edson JV Cash on Hand) 5 Day Weighted Avg. Trading Price PMT.DB.D $99.9 million 7.25% $7.50 January 31, 2015 $ PMT.DB.E $59.9 million 7.00% $7.00 December 31, 2015 $ Close to 45% of debt has term into

21 Financial Overview and Guidance

22 Millions Millions Millions Millions Historic Revenue and EBITDAX $450 $400 $350 $412 $344 $300 $250 $255 $270 $300 $250 $200 $150 $100 $50 $233 $197 $199 $200 $200 $150 $100 $50 $110 $84 $91 $99 $ LTM-Mar Net Production Revenue 14 $ LTM-Mar Adjusted EBITDAX 14 $300 $250 $200 $150 $237 $252 $240 $173 $192 $211 $140 $120 $100 $80 $89 $115 $108 $84 $99 $100 $60 $55 $50 $40 $ LTM-Mar Unhedged Net Production Revenue 14 $20 $ LTM-Mar Unhedged Adjusted EBITDAX 14 22

23 2014 Capital Spending Total Capital: $87 million + $85 million East Edson JV Q Wells Capital Q2-Q Wells Capital Wells Total Capital West Edson (1) 2 gross (1.0 net) $13 MM 10 gross (5 net) $33 MM 12 gross (6.0 net) $ 46 MM East Edson (2) 1 gross (1.0 net) $6 MM 14 gross (14.0 net) $ 85 MM 15 gross (15.0 net) $ 91 MM Mannville Heavy Oil (3) 11 gross (9.7 net) $11 MM 9 gross (7.8 net) $17 MM 20 gross (17.5 net) $ 28 MM Eastern Shallow Gas and Other Recompletions/ Workovers/ Optimization $1 MM $6 MM $7 MM Total $31 MM $141 MM $ 172 MM 1) Includes 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 Perpetual escrowed funds and including portion of facility capital for equipment for 30 MMcf/d East Edson plant to be constructed in ) Includes $3 million of expanded waterflood capital 2014 Capital focused on proven diversifying plays 23

24 WTI (US$/BBL) 2014 funds flow 2014 Capital Spending of $172 million Production of 20,100 boe/d (19,500 boe/d net of East Edson JV Royalty) 2014 Funds Flow AECO ($/GJ) ) 2014 settled and forward prices from June through December at June 25, 2014 were $4.20/GJ at AECO and US $101.10/bbl WTI 2014 funds flow estimated at ~$92 million at current commodity prices 24

25 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) ) 2015 settled and forward prices from June through December at June 25, 2014 were $4.00/GJ at AECO and US $96.95/bbl WTI 2015 funds flow estimated at ~$122 million at current commodity prices 25

26 Projected balance sheet reconciliation Q1 Capitalization Q1 Net bank debt $84 Senior unsecured notes $150 Convertible debentures $160 $394 Q2 Capitalization (Est) July-August 2014 Transactions (1) H Operations (2)(3) 2015 Operations Sources Sources Sources Sources Funds flow $26 East Edson JV royalties $120 Funds flow $49 Funds flow $122 Monetization of Gas Over Bitumen $19 Issue of Senior Unsecured Notes $100 Withdrawal of East Edson escrows $64 Withdrawal of East Edson escrows $36 West Central A&D $3 Increase in bank debt $13 Increase in bank debt $22 $48 $220 $126 $180 Uses Uses Uses Uses Q2 capital program $13 East Edson JV escrows $100 "Normal" capex $41 "Normal" capex $65 Reduction in bank debt $35 Redeem convertible debentures D $100 East Edson capex $85 East Edson capex $55 Reduction in bank debt $20 Repay convertible debentures E $60 $48 $220 $126 $180 Period-end Capitalization Period-end Capitalization Period-end Capitalization Period-end Capitalization Net bank debt (4) (5) $49 Net bank debt (4) (5) $29 Net bank debt (4) (5) $42 Net bank debt (4) (5) $64 Senior unsecured notes $150 Senior unsecured notes $250 Senior unsecured notes $250 Senior unsecured notes $250 Convertible debentures $160 Convertible debentures $60 Convertible debentures $60 Convertible debentures (6) - $359 $339 $352 $314 (1) Includes proceeds from East Edson JV; $30MM of proceeds from producing royalty sale in escrow for East Edson spending (2) Assumes H and 2015 commodity prices as per forward market as at July 9, 2014 (3) Assumes recovery of sunk costs and first well spending on East Edson JV activity from Perpetual Escrow Funds (4) Includes $11 million long term Crown receivable for GOB financial solution at March 31, 2014; Reduces to $0 by Dec 31, 2015 (5) Debt estimates are period end (6) 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

27 Projected borrowing base and credit ($ Millions) Q Q Q2 Pro forma East Edson JV July 16 Q2 Pro forma High Yield Financing H Proforma East Edson JV and HY 2015 Proforma East Edson JV and HY East Edson Escrow Funds - - (100) (100) (36) - Projected Bank Borrowing Base Net Bank Debt Senior Unsecured Notes New High Yield Unsecured Notes Convertible debentures PMT.DB.D Convertible debentures PMT.DB.E Total Net Debt excluding escrow Convertible Debentures High Yield Unsecured Notes Consolidated Debt Consolidated Senior Debt EBITDA Consolidated Debt to EBITDA Consolidated Senior Debt to EBITDA Undrawn Credit Capacity ex escrow (1) Consolidated debt per credit facility excludes convertible debentures ; Credit facility covenant limits ratio to 4 times (2) Consolidated senior debt per credit facility excludes convertible debentures and high yield unsecured notes; Credit facility covenant limits ratio to 4 times Credit Facility Covenants Maintenance Based Note Indenture Covenants Incurrence Based 27

28 2. Key Priority Grow Edson liquids-rich gas production, reserves, cash flow, inventory and value 28

29 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) Compressor Capacity 30 MMcf/d 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 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 Q1 Drill 2014 Q2-Q4 Planned Drill 2015 Proposed Location East Edson JV Lands Inventory of 175 locations of which 128 gross (104 net) booked in reserve report Defining optimal spacing through infill well performance may lead to additional inventory

30 Edson Wilrich Type Curves Three type curves define reserves and inventory 30

31 Wilrich value potential West Edson Projected Economics per Drilling Location Capital (D,C & T) 10 % ROR F&D Capital Efficiency Payout $6.4 MM gross $10.7 MM BT gross 168% BT $6.83/boe ~ $8,300 boe/d (first 12 months) 0.8 Years Recycle Ratio 3.7 Assumptions (McDaniel Year End 2013) 2014 Pricing $3.60/GJ; $79.90/bbl NGL Operating Costs Well Depth Type Curve 2P Reserves Royalties $1.62/boe (first year) 4,200M HZ; 2,700M TVD IP 9 MMcf/d 1 year exit rate 2.6 MMcf/d 9 bbl/mmcf C Bcfe sales per well 5% royalty until NGDDP credit of ~$2.3 MM is recovered Inventory of 34 net locations at 2 wells per section Monitoring infill well performance to evaluate locations at increased drill density 31

32 East Edson JV type curve economics Projected Economics per South West Drilling Location (McDaniel April 2014 Price) Projected Economics per North East Drilling Location (McDaniel April 2014 Price) Capital (D,C & T) $ 5.1 MM Capital (D,C & T) $ 5.0 MM 10 % $ 5.3 MM 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 Realized Price Assumptions (McDaniel April 2014 Price) $ 4.76 / Mcf; $ / bbl Condensate Recycle Ratio Realized Price Assumptions (McDaniel April 2014 Price) $ 4.88 / Mcf; $ / 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 98 gross (89 net) locations identified within the McDaniel report for East Edson 32

33 Boe/d Cumulative Production (MBoe) Greater Edson liquids-rich gas play performance 12,000 14,000 40% net production growth expected in ,000 8,000 12,000 10,000 8,000 Driven by West Edson capacity expansion in 2014 Flat production forecast at Edson net to Perpetual as Royalty on Developed Lands is sold but sale is offset by Perpetual production growth from JV drilling 6,000 4,000 6,000 East Edson to drive growth in 2015 Drill to fill West Edson capacity of 30 MMcf/d net 2, E2015E 4,000 2,000 - Drill to fill existing East Edson facilities through compressor Construct new East Edson plant and bring online in September 2015 at 30 MMcf/d net Edson West Edson Liquids-rich gas growth area to be built from 0 to close to 11,000 boe/d in 5 years Infrastructure and inventory in place for continued growth 33

34 3. Key Priority Maximize value of Mannville heavy oil 34

35 Eastern Alberta Conventional heavy oil Discovered 14 Mannville pools 8 Lloyd, 5 Sparky, 1 Basal Quartz > 200 MMbbl Original Oil in Place > 10 5% recovery factor Current Production ~ 3,100 bbl/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 Extensive in-house 3D & 2D seismic 123,000 net acres of lands 2014 Capital Activity Q1 9 gross (8 net) development infill wells 2 (1.7 net) new pool tests successful Q Development Q New Pool Tests H Drilling 2014 Q2-Q4 Capital Plan 9 gross (7.8 net) wells Waterflood Implementation in I2I Pool Water support injection conversions in 2-3 additional pools Planning for 2015 EOR Pilot New pool tests designed to add 20+ drill ready development locations 35

36 Upper Mannville A pool Lloyd Channel OOIP = 30.5 MMbbl Cumulative production to date ~1.0 MMbbl ( ~ 3% RF) Booked Reserves (year end 2013) 1.4 MMbbl (7% RF) 24 wells drilled to date 4 additional multi-laterals in 100m spacing Start pressure maintenance with water injection in 2014 LLOYD CHANNEL TYPE LOG 100/ W4/00 Downspacing to 50m infills in A pool could add up to 20 low risk laterals 36

37 Mannville heavy oil value potential Projected Economics Per Well Lloyd Sparky Capital (D,C & T) $1.2 MM $1.2 MM 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 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 37

38 Gross Oil Production m3/d Waterflood and enhanced oil recovery 200 Mannville I2I Waterflood Pilot Pool Sparky Mid Type Log 100/ W4/00 > 24 % DENSITY POROSITY 6 m OIL PAY Sparky Mid Sand Sparky I2I Pool Primary Production vs. Waterflood 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 Q Up to 3 additional wells in H Implementing Waterflood in 2014 Water injection began Dec 2013 (2 wells) 3 injector conversions in Q Reservoir simulation and lab work for polymer flood underway Case 1- Develop. (NO WF) - Oil Prod. (m3/d) Case 2- Develop. and WF - Oil Prod. (m3/d) Jan-14 Jan-19 Jan-24 Jan-29 Waterflood value created through reduction in primary production decline 38

39 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) % Upper Mannville A % Upper Mannville B % Total % Significant scope for increased reserves and value through waterfloods and possible polymer floods 39

40 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 $50 $40 $30 $20 $10 $180 $130 $80 $30 Transitioning from growth to sustaining production in 2014 Drilling capital reduced $0 4, E -$20 4,500 Investing in facilities for waterflood 3,500 3,000 2,500 2,000 1,500 1, E 4,000 3,500 3,000 2,500 2,000 1,500 1, Significant value to be created through waterflood & EOR Evaluating waterflood performance on I2I $90 $80 $70 $60 $50 $40 $30 $20 $10 $ E $200 $150 $100 $50 $0 Injection to start pressure maintenance in 2-3 other pools Scoping polymer flood costs and potential Heavy oil portfolio built from 0 to 3,500 boe/d in 3 years Investment recovered with cash flow now exceeding future capital spending 40

41 4. Key Priority Maximize cash flow from shallow gas 41

42 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: ~ 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) from Q spending High capital efficiencies of <$5,000 boe/d in Q1 program 42

43 5. Key Priority Advance and broaden portfolio of high impact opportunities with risk-managed investment Viking/Colorado Shallow Shale Gas Bitumen Exploration 43

44 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 Resource Potential > 1 Tcf Potential Recoverable Resource calibrated to 675m of core 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 Technology optimization pilot program ready to execute 44

45 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 290m shale group Advanced detailed (3G) technical study Gas in Place, brittleness mapping, production inflow and fracture modeling Evaluated induced fracturing recompletions Monitor industry horizontal drilling programs Plan and execute technology optimization program through: Recompletions Vertical wells Horizontal drilling program Frac designs Small third party drilling commitment 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 45

46 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 46

47 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, 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 Submitted ERCB application IETP funding approved Water source well drilled 47

48 LEAD process technology pilot Low pressure electro-thermally assisted drive Pilot planned for 2015 Approvals pending $18.2 million expected capital and operating costs over pilot life (3 years) IETP funding (30%) $5.5 million Modelled rates of >200 bbl/d of oil from single producer 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 48

49 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 49

50 Investment Thesis

51 Strong annual growth forecast 2014 Key diversifying plays production growth of ~22% Growth focused at West Edson Disposition of royalty on developed lands in exchange for $50 million and $70 MM farm-in funding Funds flow and funds flow per share growth of >50% Significant downside commodity price protection in place Disposition program targeting $100 million in debt reduction Monetized $73.5 million Generated $70 million in additional capital funding through farm-in 2015 Gas and NGL production growth >20% through low risk development of East Edson liquidsrich gas Mannville heavy oil infill drilling and waterfloods to sustain production and grow funds flow Begin to backfill conventional shallow gas declines with Viking/Colorado Funds flow growth 35-40% will reduce leverage ratios Projected YE2015 debt to cash flow ratio of 2.7 times based on strip pricing Highly leveraged to strengthening 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 51

52 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% Q2 2014E 0% Shallow Gas Mannville Heavy Oil Other Deep Basin Elmworth West Edson East Edson % of Diversifiying Assets 1) 2014E is estimated as at May 1, 2014 giving effect to East Edson JV Reserve growth in higher value diversifying assets 52

53 Sum of the parts NAV Per Share (1) WGS LP valued at prorata 2013 buyback acquisition value in all scenarios Trading at <half of reserve-based net asset value 53

54 Future growth and value creation 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 54

55 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 55

56 FOR ADDITIONAL INFORMATION Susan L. Riddell Rose President & CEO Additional Information Cameron R. Sebastian Vice President, Finance & CFO 3200, Avenue SW Calgary, Alberta Canada T2P 3H TOLL FREE PHONE FAX info@perpetualenergy.com

57 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 ("NI ") 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 , 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 , the COGE Handbook or CSA Notice 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 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. 57

58 Appendix

59 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 Initial working gas capacity 17 Bcf 30% Perpetual Interest Sold 90% in 2012 with buyback option Exercised buy back option for 20% repurchase in May 2013 ($19 million) Expansion Potential 2 new wells and stage 1 delta pressuring completed to establish 21.5 Bcf current working gas capacity Stage 2 delta pressuring to increase working gas to 24.5 Bcf with minimal incremental operating costs 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 59

60 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 $ Hedging Gain Options Premium Gas price risk management positions in place mainly for 2014 More volume and length to oil price hedges 60

61 Gas price risk management Type of Contract Term Volumes (GJ/d) Fixed Price ($/GJ) Futures Price (1) ($/GJ) % of 2014 Natural Gas Production (2) AECO Fixed Price Financial Jul ,914 $4.32 $4.38 6% AECO Fixed Price Financial Jul Oct ,100 $4.02 $ % AECO Fixed Price Physical Jul Oct ,275 $4.06 $4.24 4% AECO Fixed Price Financial Jul Dec ,500 $4.09 $ % AECO Fixed Price Financial Call Jul Dec ,000 $4.25 $4.25 8% AECO Fixed Price Financial Nov Dec ,000 $4.80 $ % AECO Basis Financial Aug Oct ,500 ($0.48) ($0.25) 6% 1) July 3, 2014 forward prices 2) Calculated using 2014 estimated actual and deemed gas production of 126 MMcf/d Gas price risk management positions in place mainly for Q1 Q

62 Oil price risk management Type of Contract Term Volumes (bbl/d) Fixed or Floor Price ($/bbl) Ceiling Price ($/GJ) ($/bbl) Futures Price (1) ($/bbl) % of 2014 Oil & NGL Production (2) WTI collars Jul Dec ,500 US $86.67 US $95.15 US $ % WTI collars Calendar ,000 CAD $87.50 CAD $95.50 US $ % WTI Calls Jul - Dec ,000 US $ US $ % WTI Calls Jul - Dec 2014 (2,000) US $ US $ WTI Calls Calendar ,500 US $ US $ % WTI Calls Calendar US $90.00 US $ US $ % WTI Fixed Price Jul - Dec US $ US $ % WTI-WCS Differential Jul - Dec ,000 US ($21.64) - US ($22.45) 68% 1) July 3, 2014 forward prices 2) Calculated using 2014 estimated oil and NGL production of 2,947 bbl/d More volume and length to oil price hedges 62