C I B C E n e r g y C o n f e r e n c e | A p r i l 2 0 1 4

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 andprojections about its business and operations. Words and phrases such as "anticipates," "expects," "believes," "estimates," "projected," "future," "goals," "forecast," "plan,""opportunities," "upside," "will," "impact," "target," "2012 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 toresource‐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 five strategic priorities for 2013.These statements are not guarantees of future performance and are subject to certain risks, uncertainties and other factors, some of which arebeyond 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 noobligation 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 offuture production of natural gas and oil due to numerous factors including permit delays or restrictions, weather, equipment failures, delays or lack of availability, unexpectedsubsurface 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 thananticipated, and changes in applicable regulations and laws; unexpected problems with wells or other equipment, unexpected changes in operating costs and other expenses, includingutilities, 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 pricediscounts and basis differentials; difficulties in accurately estimating the discovery, volumes, development potential and replacement of natural gas and oil reserves; the impact ofeconomic conditions on our business operations, financial condition and ability to raise capital; variances in cash flow, liquidity and financial position; a significant reduction in ourbank 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 toperform or fulfill their obligations under existing agreements; write downs of our asset carrying values and oil and gas property impairment; the discovery of previously unknownenvironmental issues; changes in our business and financial strategy; inaccuracies in estimating the amount, nature and timing of capital expenditures, including future finding anddevelopment 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 andtransportation 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 theintroduction 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 andthe occurrence of natural disasters such as fires, floods, hurricanes, earthquakes and other catastrophic events and natural disasters; the high‐risk nature of drilling and producingnatural 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 governmentalregulation 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 changedaccounting rules under generally accepted accounting principles and IFRS promulgated by rule‐setting bodies; the amount of future abandonment and reclamation costs, assetretirement 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 andmanagement's discussion and analysis and Annual Informational Form and our other filings on SEDAR. Unpredictable or unknown factors not discussed herein also could have materialadverse effects on our business and operations and on the forward‐looking statements contained herein.

Perpetual Energy – TSX:PMT

DIVERSIFIED

RESOURCE – STYLE

GROWTH – ORIENTED

ENTREPRENEURIAL

EXPLORER, PRODUCER & MARKETER

BUILT TO GROW BUILT TO PROSPER BUILT TO LAST

Conventional

Shallow Gas

Distributing Trust

3

Common shares outstanding 148.5 million Management ownership 25.34% Share price (5 day weighted average) $ 1.39 30 day weighted average daily trading volume ~ 421,000 shares/day

Market capitalization $ 206 million

Total Net Debt $ 377 million Net bank debt $ 67 million Convertible debentures $ 160 million Senior unsecured notes $ 150 million

Enterprise value $ 583 million

Operating profile

4

Actual & Deemed Production (Q4 2013) 21,809 Boe/d

Natural Gas 90.3 MMcf/d

Oil and NGL 3,509 bbl/d

Gas over Bitumen Deemed Production(1) 19.5 MMcf/d

P+P Reserves(2) 62.4 MMboe

Reserve to Production Ratio (P+P) (RLI)(2) 8.6 Years

Contingent Resource – Bitumen(3) 279 MMbbl

Warwick Gas Storage Working Gas Capacity (gross)(4) 21.5 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 at year end 2013(3) Best estimate as evaluated by McDaniel(4) 30% ownership interest

• Conventional Shallow Gas• Mannville Heavy Oil• Bitumen • Warwick Gas Storage• Viking/Colorado Shallow Shale Gas

Eastern Alberta

• Edson Wilrich• Multi-Zone Liquids-Rich Gas• Tight Oil and Gas Exploration

Deep Basin

Diversified portfolio – Built to prosper

5Spectrum of opportunities to invest in through variable commodity cycles

Mannville

Mannville EOR

Heavy Oil Exploration

HEAVY OIL

Edson Wilrich

Greater Edson Multi-zone

Deep Basin Exploration

LIQUIDS-RICH GAS

Eastern Alberta Conventional

Viking/Colorado Shallow Shale Gas

SHALLOW GAS BITUMEN

Panny Bluesky

Liege Grosmont& Leduc

Marten Hills Clearwater

Other

OTHER

Warwick Gas Storage (30%)

GOB Technical Solutions

Exploration

Portfolio management strategy

6Entrepreneurial approach to value creation

Invest for growth Eastern Alberta heavy oil

Edson liquids-rich gas

Maximize cash flow Conventional shallow gas

Warwick Gas Storage

Optimize and Advance Viking/Colorado shale gas

Bitumen

GOB technical solutions

Tight oil & gas exploration

MEDIUM AND LONG TERM

VALUE STRATEGIES

PROVENDIVERSIFYING

GROWTH STRATEGIESCASH FLOW

GENERATORS

52%OF PRODUCTION

59%OF RESERVES

62%OF REVENUE

70%OF RESERVE VALUE

Commodity diversification

8Oil and NGLs contributed almost 50% of revenue in 2013

Revenue from Oil and NGL

Oil

NGL

Deep Basin gas(1)

Shallow gas

Warwick Gas Storage

2014 Forecast Revenue

(1) Blended heat content estimated at 1.092 GJ/Mcf compared to 1.045 GJ/Mcf for dry gas

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2009 2010 2011 2012 2013 2014E

Revenu

e ($MM)

Oil and NGL Revenue

Oil and NGL % of Revenue

Oil and NGL Production

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500

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2009 2010 2011 2012 2013 2014E

Percen

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ction (%

)

Oil an

d NGL Prod

uctio

n (bbl/d)

NGL Sales Oil Sales% Oil and NGL of Total Production

9Strong production growth profile in diversifying assets

Asset base transformation

Resource-style growth assets 43% of production in 2013 and growing

2014 Focus Grow Deep Basin production Optimize heavy oil businessMitigate declines in shallow gas

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2009 2011 2013

Growth Asset Produ

ction (bbl/d)

Mannville Heavy Oil

Deep Basin Gas

Deep Basin NGL

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2009 2010 2011 2012 2013 2014E

Prod

uctio

n (%

 of total)

OilNGLDeep BasinE. Shallow Gas

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

10Strategic priorities focus our activities

1. Key priority

11

Reduce debt and manage downside risk

Balance sheet

Net Bank Debt: $67 million (YE 2013) Borrowing base on credit facility – $110 million Next semi-annual redetermination – April 2014

Senior Unsecured Notes: $150 million Coupon rate - 8.75% Maturity date - March 2018

Convertible Debentures: $160 million Repayable in cash or equity at Perpetual’s discretion 2015 maturities Senior notes provisions should not restrict cash repayment Normal Course Issuer Bid in place

12Over 80% of debt has term into 2015 and beyond

Total Current Net Debt: $377 million

TSX SymbolAmount

OutstandingCoupon

RateConversion

PriceMaturity

Date

5 Day Weighted

Avg. Trading Price

PMT.DB.D $99.90 million 7.25% $7.50 January 31, 2015 $99.47

PMT.DB.E $59.86 million 7.00% $7.00 December 31, 2015 $99.58

Debt Reduction

13$248 million in dispositions in 2012 and 2013Targeting another $100 million in asset sales for debt reduction in 2014

23 Transactions Closed in 2012

Total Net Proceeds: $167.2 MM

4 Transactions Closed 2013

Net Asset Sale Proceeds: $79.0 MMProduction: 16 Boe/dP+P Reserves: 13.1 MMBoe Reduction in FDC: $122.8 MM

Trioil Shares $1.9 MM

Total Net Proceeds: $80.9 MM

Diversification – Warwick Gas Storage

14Non-depleting, long life, diversifying assetNear term cash flow growth potential

• 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 LeasesWell Site PadStorage Facility PipelineHorizontal Wells2012 Hz WellsTCPL 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

Expanding Working Gas Capacity 2 new wells and stage 1 delta pressuring

• 21.5 Bcf working gas Stage 2 delta pressuring planned for

Summer 2014 – Winter 2015 cycle• 24.5 Bcf working gas with no

incremental operating costs

30% Perpetual Interest Sold 90% in 2012 with buyback option Exercised buy back option for 20%

repurchase in May 2013 ($19 MM)Manage WGS LP for annual fee

Diversified Cash Flow 2012 & 2013 ~$11 MM/year gross 2014 Forecast $15 MM gross

Commodity price risk management strategy

15Gas price risk management positions in place mainly for Q1 to Q3 2014More volume and length to oil price hedges

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

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2009 2010 2011 2012 2013

Hed

ging

Gai

n/Lo

ss (

$MM

)

Hedging Gain Options Premium

2. Key Priority

16

Grow Edson liquids-rich gas production, reserves, cash flow, inventory and value

Edson Wilrich liquids-rich gas

17Inventory of >110 Wilrich horizontal locations and growingDefining optimal spacing through infill well performance assessment in 2014

Pipeline To EdsonDeep Cut Plant

01-34 Gas Plant • Capacity 30 MMcf/d• Expanding to 60 MMcf/d by Q3 2014 16-10 Compressor

Capacity 30 MMcf/d

Vertical Well

Pre-2013 Horizontal Well

2013 Horizontal Well

2014 Budget Location

2014 Ready to Execute

West Edson• Type Curve IP 9.0 MMcf/d• 9 bbl/MM C5+• Reserves 5.6 Bcfe/well• 30 (15 Net) P+PUDs booked

Edson• Type Curve IP 4.6 MMcf/d/ • 35 bbl/MM NGL• Reserves 2.7 Bcfe/well• 21 (17 net) P+PUDs booked

PMT Sales Pipeline to Alliance Constructed in 2013

To Rosevear Plant (15% WI)

Wilrich value potential – Edson

18Inventory of 76 net locations at average of 2 wells per sectionModeling work supports possible additional 54 locations at increased drill density

Projected Economics per Drilling Location

Capital (D,C & T) $ 5.1 MM

NPV @ 10 % $ 3.3 MM

ROR 47% BT

F&D $11.30 / boe

Capital Efficiency <$13,850 boe/d (first twelve months)

Payout 1.9 Years

Recycle Ratio 2.4

Assumptions (McDaniel Year End 2013)

2014 Pricing $3.60/GJ; $68.77/bbl NGL

Operating Costs $3.38/boe (first year)

Well Depth 4,000M HZ; 2,400M TVD

Type CurveIP 4.6 MMcf/d1 year exit rate 1.0 MMcf/d34 bbl/MMcf sales NGL/condensate

2P Reserves 2.7 Bcfe per well

Royalties 5% royalty until NGDDP credit of ~$2.2 MM is recovered

Risk Unrisked

Wilrich value potential – West Edson

19Inventory of 34 net locations at 2 wells per sectionMonitoring infill well performance to evaluate additional 16 locations at increased drill density

Assumptions (McDaniel Year End 2013)

2014 Pricing $3.60/GJ; $79.90/bbl NGL

Operating Costs $1.62/boe (first year)

Well Depth 4,200M HZ; 2,700M TVD

Type CurveIP 9 MMcf/d 1 year exit rate 2.6 MMcf/d9 bbl/MMcf C5+

2P Reserves 5.6 Bcfe sales per well

Royalties 5% royalty until NGDDP credit of ~$2.3 MM is recovered

Risk Unrisked

Projected Economics per Drilling Location

Capital (D,C & T) $6.4 MM gross

NPV @ 10 % $10.7 MM BT gross

ROR 168% BT

F&D $6.83 / boe

Capital Efficiency < $8,308 boe/d

Payout 0.8 Years

Recycle Ratio 3.7

Edson liquids-rich gas play performance

20Liquids-rich gas growth area built from 0 to 4,900 boe/d in 3 yearsInfrastructure and inventory in place for continued growth

Edson

West Edson

30% production growth expected in 2014Drill to fill expanded West

Edson capacity of 30 MMcf/d net

Modest decline at Edson with limited capital

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Cumulative Prod

uctio

n (M

Boe)

Boe/d

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2009 2011 2013

Cumulative Ca

sh Flow ($

MM)

Ope

ratin

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sh Flow ($

MM)

3. Key Priority

21

Maximize value of Mannville heavy oil

Eastern Alberta – Conventional heavy oil

22New pool tests designed to add 20+ drill ready development locations

Discovered 13 Mannville pools 7 Lloyd, 5 Sparky, 1 Basal Quartz > 200 MMbbl Original Oil in Place > 10 MMbbl @ 5% recovery factor Current Production ~ 2,800 bbl/d

Low cost HZ development HZ $ 1.1 MM single lateral well $1.4 MM for multi-lateral well Average initial rate ~80 bbl/d Extensive in-house 3D & 2D seismic 123,000 net acres of lands

2014 Capital Activity

Q1 8 gross (7 net) development wells 1 new pool on production at 140 bbl/d oil 2 additional new pool tests underway

Full Year 23 gross (18 net) wellsWaterflood Implementation in I2I Pool Injection conversions Upper Mannville ‘A’ Planning for 2015 EOR Pilot3D coverage

Mannville

Q1 2014 Development

Q1 2014 New Pool Tests

H2 2014 Drilling

Upper Mannville ‘A’ pool – Lloyd Channel

23Downspacing to 50m infills in ‘A’ pool could add up to 20 low risk laterals

LLOYD CHANNEL TYPE LOG100/04-36-050-09W4/00

OOIP = 30.5 MMbbls Cumulative production to date ~800 Mbbl ( ~ 2.6% RF) Booked Reserves (year end 2013) 1.4 MMbbl (7% RF) 18 wells drilled to date 6 additional multi-laterals in inventory

Mannville heavy oil value potential

24Highly profitable at current oil prices

Projected Economics Per WellLloyd 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 per Boe/d ~$ 25,000 per Boe/d

Recycle Ratio 3.0 2.7

Oil over shakers while drilling Sparky development pad HZ pad site

Assumptions(McDaniel Year End 2013)

2014 Pricing $68.90/bbl Wellhead heavy priceWTI $US95/bbl, WCS $US23.5/bbl, offset $7.60/bbl

Operating Costs $6.23 /Boe (first year) &$12.60/Boe (lifetime)

Average Well Lloyd IP 120 bbl/d to 75 bbl/d after year 1Sparky IP 85 bbl/d to 44 bbl/d after year 1

2P Reserves 90 Mbbl per Lloyd well60 Mbbl per Sparky well

Royalties 5% for first 18 months on Crown; variable on Freehold

Mannville heavy oil play performance

25Heavy oil portfolio built from 0 to 3,500 boe/d in 3 yearsInvestment recovered with cash flow now sustaining capital expenditures

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2009 2010 2011 2012 2013 2014E

Cum

ulat

ive

Cap

ital

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MM

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Cap

ital

($M

M)

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Cum

ulat

ive

Pro

duct

ion

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oe)

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duct

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(Boe

/d)

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Cum

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ash

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M)

Waterflood and enhanced oil recovery

26Significant scope for increased reserves and value through infill drilling, waterfloods and possible polymer floods

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 Q1 2014

Up to 8 additional wells in H2 2014

Waterflood

Water injection began Dec 2013 (2 wells)

3 additional injector conversions in Q2 2014

Reservoir simulation and lab work for polymer flood underway

Sparky Mid Type Log100/09-32-050-08W4/00

6 m  OIL PAYSparky Mid Sand

> 24 % DENSITY POROSITY

Select Pools (1) OOIP (2)

(MMbbl)

Cumulativeproduction 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

Mannville I2IWaterflood Pilot Pool

4. Key Priority

27

Maximize cash flow from shallow gas

Conventional shallow gas

28Cash flow and value highly leveraged to gas price recovery

Belly River

Viking

Grand Rapids

Lower Mannville

Pre Cretaceous Unconformity

East Central and Northeast Alberta

Cretaceous and Devonian sweet shallow gas

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

5. Key Priority

29

Advance and broaden portfolio of high impact opportunities with risk-managed investment

• Viking/Colorado Shallow Shale Gas• Bitumen• Exploration

30

Viking/Colorado shallow shale gas

Belly River Play FairwayCardium/ Colorado WellsPerpetual LandsViking Proved UndevelopedViking Probable UndevelopedViking Proven Non-ProducingProspect 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

Pilot program ready to execute

Colorado group technical advancement

Colorado group free gas in place

31Resource is widely distributed

Total Resource in Place > 130 Tcf OGIP estimated to average 16

Bcf/section

Proven recovery from Cardium equivalent zone through horizontal development

Potential in up to 6 zones within 290m shale group

2011 - 2012 Advanced detailed (3G) technical study

Gas in Place, brittleness mapping, production inflow and fracture modeling

Pilot work evaluated fracture performance through recompletions

2013 - 2014Monitor industry horizontal development

pilots

Pilot planning and execution Recompletions Vertical wells Horizontal pad wells Frac designs

32

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

>3 Billion bbls OBIP independently recognized at Liege and Panny 278 MMbbl contingent resource

467 MMbbl additional prospective resource

Perpetual OS Leases

Fireflood ProjectsCSS Projects

Primary Projects

Oil Pipelines

SAGD Projects

Electric Heaters

33

Bitumen – Panny Bluesky

Excellent reservoir quality in Bluesky homogeneous shoreface sand facies

2010/11 Vertical Wells

Existing Horizontal Well

8m Bitumen

10m Bitumen

RoadsNatural Gas Pipeline Oil Well Effluent PipelinePerpetual Gas PlantPerpetual Oil Sands RightsOther Perpetual Lands

Low rate cold flow without solvent or thermal assistance

Average pay thickness 11 m

Low viscosity bitumen ~15,000 cp @ 25oC 50,000 cp at 11oC reservoir temp Highly mobile at ~70oC

Panny Bluesky Resource Assessment (McDaniel P50) 755 MMbbl Discovered OBIP 132 MMbbl Contingent Resource 17.5% recovery factor applied

utilizing horizontal cyclic steam

Resource to support 15,000 bbl/d commercial project for 20 to 25 years

Technology pilot pending Submitted ERCB application LEAD

• Electrical heat w water &/or solvent

IETP funding approvedWater source well drilled

LEAD process technology pilot Low pressure electro-thermally assisted drive

34Electrical heating cable with water injection for mobility and pressure support Expected pilot start-up 2015

Production Facilities

Power source

Producing Wellhead

Overburden

Underburden

Injection Facilities

Pay Zone

TOB1 TOB2 TOB313-34 POB

Pilot Plan $18.2 MM capital and operating costs over

pilot life (3 years)

IETP funding (30%) $5.5 million

35

Bitumen – Liege carbonates

Excellent reservoir quality vuggy porosity in Grosmont

Shell

AOC

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’

2014 Capital spending

2014 Capital spending plan

Total Capital: $70 - 80MM

372014 Capital focused on proven diversifying plays

Q1 2014Wells Capital

Q2-Q4 2014Wells Capital

TotalWells Capital

West Central Deep Basin

3 gross (2.0 net)

$18 MMUp to 7

(3.5 net)$21-$26 MM

Up to 10 (5.5 net)

$39-$44 MM

Mannville Heavy Oil 11 gross (9.7 net)

$13 MMUp to 12 (8.3 net)

$11-$14 MMUp to 23(18 net)

$24-$27 MM

Eastern Shallow Gas

Recompletion/Workovers/

Facility Optimization

$4 MM $3-$5 MM $7-$9 MM

Total $35 MM $35-$45 MM $70-$80 MM

1) Includes facility capital to expand West Edson to 60 MMcf/d gross (50% WI)

Investment thesis

Strong annual growth

2013 (versus 2012)

Oil and NGL production growth of 12%

Mannville oil production growth of 24%

Deep basin production growth of 14%

Funds flow and funds flow per share growth of 19%

Debt reduction from year end 2012 of 3%

2014 (versus 2013)

Key diversifying plays production growth of ~16%

Funds flow growth of ~40-50%

Significant downside commodity price protection in place

Leveraged to gas price recovery

Every $0.50 per Mcf = $5 million of annual funds flow (~5% increase)

Fully exposed to gas price recovery in 2015 with no material gas hedge positions

Disposition program targeting $100 MM in debt reduction

39Year over year growth forecast on top priorities

Sum of the parts

40Trading at <1/2 of ‘Reserve-based’ Net Asset ValueAnd 80% of Reserve-only NAV, excluding any undeveloped land valuation

-$500.00

-$250.00

$0.00

$250.00

$500.00

$750.00

$1,000.00

$1,250.00

Liabilities Reserve-Based NAV Prospect Inventory Risked Prospect Inventory UnRisked

NP

V 8

% (

$MM

)

Undeveloped Land

Bitumen

Mannville PI

Viking/Colorado PI

Conventional Shallow Gas PI

Edson/West Edson PI

Gas Over Bitumen

Warwick Gas Storage

Proved + Probable Developed

Proved + Probable Undeveloped

Hedge Book

Bank Debt

Senior Notes

Convertible Debenture

Net ARO

Unrisked NAV $7.19/Share

Reserve Based NAV $3.07/Share

$5.10

$1.70

$0

-$1.70

-$3.40

$6.80

$3.40

Risked NAV $4.91/Share

$8.50

NAV Per Share

(1) WGS LP valued at proportionate 2013 buyback acquisition value in all scenarios

PMT investment thesis

Asset base repositioning for resource-style oil and NGL diversification successful

Mannville heavy oil delivering results with material secondary recovery growth potential Edson Wilrich liquids-rich gas inventory proven and highly economic

Execution and operational excellence in chosen strategies

Increasing oil and NGL in commodity mix growing funds flow

40% of debt has term into 2018 providing flexibility

Asset dispositions and growing cash flow improving debt to cash flow ratios 60% drawn on credit facility Multiple ‘levers’ available to manage balance sheet and convertible debenture maturities in 2015 Pursuing further asset dispositions to continue to reduce outright debt leverage

High impact value potential from medium to long term portfolio of assets

Tremendous leverage to any gas price cycle recovery in 2015 and beyond

Trading significantly below ‘Reserve-Based’ Net Asset Value

41Spectrum of opportunity to grow and prosper

42

Important information about the presentation

Non-GAAP MeasuresThis presentation contains financial measures that may not be calculated in accordance with generally accepted accounting principles ("GAAP"). Readers are referred to advisories andfurther discussion on non-GAAP measures contained in the "Non-GAAP Measures" section of our most recent management's discussion and analysis.

IP ratesInitial 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 performanceor 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 OutlooksIncluded 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 inMarch 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 appropriatefor other purposes.

Reserves, Resource and F&D DisclosureUnless as otherwise noted, reserves and resource information included in this presentation is based on independent evaluations prepared by McDaniel and Associates Consultants Ltd. inaccordance 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" economicstatus as sub-classification into economic and uneconomic categories has not been evaluated. Contingencies affecting the classification of the resources include corporate developmentplans, 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 ofthe 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 andrisk 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 additionaldisclosure 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 futuredevelopment costs generally will not reflect total finding and development costs related to reserves additions for that year.

Projected EconomicsThis 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 "projectedcapital", "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 byPerpetual 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 arehistorical 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 WestEdson 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 severalmaterial 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 anenergy 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 gasand 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 asan indication of value.

Net Asset ValueIn 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 thecurrent 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 asnapshot 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 thefair market value of Perpetual.

FOR ADDITIONAL INFORMATION

Susan L. Riddell RosePresident & CEO

Cameron R. SebastianVice President, Finance & CFO

3200, 605 – 5 Avenue SWCalgary, Alberta Canada T2P 3H5800.811.5522 TOLL FREE

403.269.4400 PHONE

403.269.4444 FAX

info@perpetualenergy.com EMAIL

43perpetualenergyinc.com

Appendix2013 Annual

Results

2013 Top 5 strategic priorities

1. Maximize value of Mannville heavy oil

2. Position for growth of Edson liquids-rich gas

3. Manage downside risk

4. Advance and broaden portfolio of high impact opportunities with

risk managed investment

5. Prepare to maximize value from shallow gas base assets in gas

price recovery

45Strategic priorities focus our activities

2013 Top strategic priorities

1. Maximize Value of Mannville Heavy Oil• 13 Mannville oil pools discovered by year end 2013 (7 Lloyd; 5 Sparky; 1 Basal Quartz)

• Drilled 37 horizontal wells (35.7 net) for $49 million

• Increased heavy oil production 24% to 3,157 bbl/d (peak of ~3,500 bbl/d)

• Mannville heavy oil accounted for 57% of net operating income in 2013

• Reserve additions of 1.83 MMboe offsetting production of 1.36 MMboe for growth of 11% over

2012 reserves (2013 ending reserves = 4.8 Mmboe)

• Identified multiple prospects for future exploration and began executing land capture strategy

• Advancing waterflood and evaluating polymer flood potential

• Reservoir simulation model built

• Laboratory fluids work and core flood testing for water and polymer floods

• Initiated waterflood pilot in Mannville I2I Sparky pool

• Application made for waterflood expansion in pilot pool and for additional pool – review

pending

46Significant scope for increased reserves and value with infill drilling, waterfloods and possible polymer floods

2013 Top strategic priorities

2. Position for Growth of Edson Liquids-Rich Gas• Drilled 5 (2.5 net) horizontal wells• Increased gas and NGL production 12% to 4,894 boe/d (29.4 MMcfe/d)• Reserve additions of 13.64 MMboe offsetting production of 1.79 MMboe for growth of 60% over 2012

reserves (2013 ending reserves = 31.8 MMbbl)

West Edson• Expanded West Edson gas plant to stated capacity of 30 MMcf/d (50% WI) with full refrigeration and

liquids recovery (Capable of flowing >60 MMcf/d on compression bypass)

• Connected West Edson 1-34 gas plant to Alliance pipeline system through a 15.5 km sales pipeline and Perpetual owned/operated meter station

• New facility reduced operating costs, down time and gives opportunity to maximize production

• Negotiated contracts to diversify markets and capitalize on enhanced heat rate gas

• West Edson drilling increased the type curve from 3.8 Bcfe to 5.9 Bcfe gross reserves per well

Edson• Additional inventory capture through undeveloped land acquisitions

• One (0.5 net) farmout well drilled to assess portion of new lands

47Expanded capital program delivered substantial increases in production, reserves, revenue and value

2013 Top strategic priorities

3. Advance and Broaden Portfolio of High Impact Opportunities with Risk-Managed Investment

Elmworth – Sold for $77.5 MM to Crystallize Value• Drilled and completed vertical well to continue majority of South Wapiti block

Panny Bitumen• IETP funding approved (30% of sunk costs received - $0.5 MM)

• Built thermal reservoir model to optimize LEAD process

• Identified potential SAGD opportunity

Liege Bitumen• Continued to monitor industry activity to assess future potential

Viking/Colorado• Ready to execute horizontal pilot program to evaluate multi-stage fracture technologies, type curve expectations and fine-tune full scale

development cost assumptions to assess economic potential

Warwick Gas Storage• Purchased 20% on buy back option for $19 million to increase exposure to working gas capacity and cash flow growth

• Received delta-pressuring approval to 21.5 Bcf working gas capacity

Columbia• Acquired acreage and drilled one (0.5 net) exploratory well – testing underway

Waskahigan Duvernay• Farmed out to evaluate prospective condensate-rich Duvernay acreage

• Well drilled in Q4 2013 - completion expected in Q3 2014

48Long term, high impact projects advancing with modest capital spending

2013 Top strategic priorities

4. Manage Downside Risk and Reduce Debt

Decrease Costs• Operating costs down 5% from 2012 (2013 - $75.4 MM)• Interest expense decreased 11% from 2012 (2013 - $28.9 MM)• G&A down 10% from 2012 (2013 - $24.5 MM)• Implemented oil drying and rail oil delivery arrangements which increased netbacks

Protect Cash Flow Through Commodity Price Management• Established material gas hedge position through October 2013 to mitigate summer gas price downside risk brought on by unseasonably warm winter 2013

• Gas hedging gains accounted for $8.3MM in revenue• Base level of oil revenue protected for 2,250 bbl/d which exceeded internal price forecast • WTI-WCS differential fixed at $US22.79/bbl for 2,250 bbl/d

Bank Debt• Credit facility borrowing base reduced from $140MM to $110MM in April 2013 but maintained October 2013 at $110MM

• Year end reserve report supports possible increase to borrowing base at April 2014 review

Diversification• Increased diversified cash flow from WGS LP to $2.4 MM with buyback and expansion

49Myriad of strategies successfully employed to manage downside risk Cash flow growth accomplished with debt reduction

2013 Top strategic priorities

5. Prepare to Maximize Value from Shallow Gas in Gas Price Recovery

Operating Costs• Shallow gas op costs reduced $7.4MM (12.9%) from 2012• Suspended shut‐in wells and pipelines and removed unused onsite equipment to lower municipal taxes, lease and other costs by an estimated $1.7 MM/year

Recompletions/Workovers• Identified and prepared to execute 60 recompletions and workovers for Q1 2014 program• $5MM in recompletions and workovers targeting to add 6.1 MMcf/d initial production with less than a year payout in 2014

Facilities• 7 Compressor/booster compressors overhauled• 3 Facility consolidation projects identified and prepared to execute

50Modest shallow gas program ready to execute in 2014

Full year capital spending

Total Capital: $96.7

51Capital focused on proven diversifying plays

Total 2013Wells Capital

Mannville Heavy Oil 37 (35.7 net) $ 49 MM

West Central Deep Basin(1) 6 (3.0 net) $35 MM

Land, Seismic, ARO & Other $12 MM

Total $96 MM

1) Includes $15MM in facilities capital at West Edson

Production highlights

Oil & NGL production 412 bbl/d to 3,860 bbl/d, a 12% from 2012 levels• Mannville heavy oil grew 24%• Change in processing at Edson reduced NGL

Natural gas production 11% to 88.9 MMcf/d due to shallow gas declines and dispositions • Decline offset by 24% increase in Deep Basin gas

Total actual production was 18,696 boe/d, 11% from 20,142 boe/d in 2012

Total actual and deemed production 9% to 22,479 boe/d (2012 – 24,592 boe/d)

52Commodity diversification strategy increased oil and NGL to 17% of actual and deemed production

655, 3%3,205 , 14%

10,633 , 47%

4,200 , 19%

3,783 , 17%

NGL Oil Shallow Gas Deep Basin Gas GOB Deemed Production

791 , 3%2,657 , 11%

13,232 , 54%

3,462 , 14%

4,450 , 18%

2013 (22,479 boe/d) 2012 (24,592 boe/d )

Funds flow

53Cash costs, excluding royalties, down $9.3 MM from 2012

Year Ended December 31

($ Millions) 2013 2012 % Change

Revenue 210.9 206.5 2

GOB Royalty 8.9 6.9 29

Royalties 19.0 12.7 50

Op Costs 75.4 79.7 (5)

Transportation 10.2 8.8 16

E&E 3.3 3.4 (3)

Cash G&A 24.5 27.1 (10)

Interest 28.9 32.5 (11)

Funds Flow 58.5 49.1 19

Per Share 0.39 0.33 18

Change from 2012

Oil & Gas Price $32.0 MM

Oil & NGL Production $9.7 MM

Hedging Gains $24.3 MM

Gas Production $10.2 MM

Gas Storage $0.8 MM

Royalties $6.3 MM

Cash Costs $9.3 MM

Funds Flow $9.4 MM

Balance sheet reconciliation

54E&D capital expenditures and WGS LP buy back funded from funds flow and net disposition proceeds

Year Ended December 31

($ Millions) 2013 2012 % Change

Exploration & Development 96.7 79.7 21

Acquisitions, net of Dispositions (51.6) (164.5) (67)

Total Capital Expenditures 45.1 (84.8) (153)

Funds Flow 58.5 49.1 19

Net Bank Debt (1) 67.2 77.8 (14)

Long Term Debt (including debentures) 309.8 309.8 -

Total Net Debt 377.0 387.8 (3)

(1) Includes $11.0MM long term Crown receivable for GOB financial solution

Reserve distribution

55Reserves in key diversifying growth plays increased 51% year over yearMannville heavy oil and deep basin now 59% of P+P reserves, up from 32% from 2012

Mannville Heavy Oil

Deep Basin

Eastern Shallow Gas

PDP - Proved Developed Producing

2PDP - Probable Developed Producing

PNP/PUD - Proved non-producing and undeveloped

2PNP/2PUD - Probable non-producing and undeveloped

(1) Year-End 2013

Total Reserves = 62.4 MMbbl

PDP

2PDP

PNP/PUD2PNP/2PUDPDP

2PDP

PNP/PUD

2PNP/2PUD

PDP

2PDP

PNP/PUD 2PNP/2PUD

Reserve value distribution

56Value of key diversifying growth plays increased 133% year over yearMannville heavy oil and deep basin now 70% of P+P Reserve Value, up from 53% from 2012

Mannville Heavy Oil

Deep Basin

Eastern Shallow Gas

PDP - Proved Developed Producing

2PDP - Probable Developed Producing

PNP/PUD - Proved non-producing and undeveloped

2PNP/2PUD - Probable non-producing and undeveloped

(1) Year-End 2013

Total NPV 10 = $622 million

PDP

2PDP

PNP/PUD

2PNP/2PUD

PDP

2PDP

PNP/PUD

2PNP/2PUD

PDP

2PDP

PNP/PUD2PNP/2PUD

Gas price risk management

57Gas price risk management positions in place mainly for Q1 – Q3 2014

1) Mar 26, 2014 forward prices2) Calculated using Q4 2013 actual and deemed gas production of 110 MMcf/d

Type of Contract Term Volumes 

(GJ/d)

Fixed Price 

($/GJ)

Futures Price(1)

($/GJ)% of 2013Natural Gas Production(2)

AECO Fixed Price Financial Apr – Jun 2014 20,825 $4.01 $4.45 18%

AECO Fixed Price Financial Apr – Oct 2014 26,100 $4.02 $4.45 23%

AECO Fixed Price Physical Apr – Oct 2014 5,275 $4.06 $4.45 5%

AECO Fixed Price Financial Apr – Dec 2014 10,000 $3.71 $4.49 9%

AECO Fixed Price Financial Jul – Dec 2014 22,500 $4.25 $4.52 19%

AECO BasisFinancial

Apr – Oct 2014 7,500 ($0.48) ($0.225) 6%

Oil price risk management

58More volume and length to oil price hedges

1) Mar 26, 2014 forward prices2) Calculated using Q4 2013 oil and NGL production of 3,500 bbl/d

Type of Contract

Term Volumes 

(bbl/d)

Fixed or Floor Price ($/bbl)

Ceiling Price($/GJ)($/bbl)

Futures Price(1)

($/bbl)

% of 2013Oil & NGL 

Production(2)

WTI collars Mar – Dec 2014 1,500 US $86.67 US $95.15 US $96.60  43%

WTI collars Calendar 2015 1,000 CAD $87.50 CAD $95.50 CAD $99.76 28%

WTI Fixed Price Mar ‐ Jun 2014 750 US $90.00 ‐ US $99.15 21%

WTI Fixed Price Mar ‐ Dec 2014 250 US $90.00 ‐ US $96.60 7%

WTI‐WCSDifferential

Apr ‐ Dec 2014 2,000 US ($21.64) ‐ US ($20.65) 57%