Perpetual Energy Inc. Webcast Presentation

April 9, 2012

1

Cautionary Statements

Forward-Looking Information

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," "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 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 four strategic priorities for 2012; and diversification strategy scenarios for 2012 to 2015. 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.

2

Cautionary Statements continued.......

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 on April , 2012 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 February 8, 2012 press release and Perpetual's most recent Annual Information Form for applicable definitions and risk factors pertaining to Perpetual's reserve and resource disclosure. Perpetual's F&D cost as well as finding, development and acquisition costs, before and after the inclusion of changes in future development capital are disclosed under the heading "Finding, Development and Acquisition ('FD&A') Costs" in Perpetual's February 8, 2012 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@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.

Market Profile

Dividend suspended October 2011

Common shares outstanding 147 million

Management ownership 24.4%

Share price (5 day weighted average) $ 0.72

Market capitalization $ 105 million

Convertible debentures $ 235 million

Senior unsecured notes $ 150 million

Net bank debt (proforma pending dispositions) $ 20 million

Enterprise value $ 510 million

30 day weighted average daily trading volume ~325,150 shares

3

4

Perpetual Strategy – The Last 36 Months

• Build a diversified portfolio of repeatable, high return assets for growth

Capture positions in chosen strategies De-risk game changers at appropriate pace to manage risk Categorize assets for long term portfolio

Grow & harvest (keepers) Sustain & divest (funders)

• Increase oil and NGL production

• Divest of ‘funders’ when appropriate to optimize value and decrease debt

• Maintain exposure to gas price recovery

• Transition to growth-oriented corporation

Transitioning from 100% conventional shallow gas to diversified, resource-style, growth-oriented asset base

through declining gas price environment

$2.1410$1.7064

$1.0038

$0.20

$0.30

$0.40

$0.50

$0.60

$0.70

$0.80

$0.90

$1.00

$1.10

$1.20

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00

$9.00

$10.00

$11.00

$12.00

$13.00

$14.00

$15.00Nymex/Aeco Daily Settles

Nymex $US/MMBTU

Aeco 5A $C/GJ

F/X US/CDN

5

Natural Gas Prices

Declining gas price environment since 2008 Reaching full capitulation in 2012

Sustainable Growth Plus Income Strategy

Targeting a sustainable income plus growth model

BASE CASH FLOW GENERATORS:

Target to Minimize Production

Declines and Maximize Free Cash Flow DIVERSIFYING GROWTH

STRATEGIES:

Target Value And Cash Flow Growth and Diversification

DIVIDENDS:

Target Sustainability

6

Actual & Deemed Production (March 2012) 25,600 Boe/d

Natural Gas (84%) 104 MMcf/d

NGL’s and Oil (16%) 3,400 bbl/d

Gas over Bitumen Deemed Production(1) 29 MMcf/d

P+P Reserves(3) 485 Bcfe

Reserve to Production Ratio (P+P) (RLI) 9.7 Years

Contingent Resource - Elmworth Montney(3) 136 Bcfe

Contingent Resource – Panny/Liege Bitumen(2) 213 MMbbl

Warwick Gas Storage Working Gas Capacity (gross) 17 Bcf

(1) Cash Flow = 0.5 x [(deemed production volume x 0.80) x (Alberta Reference Price - $0.3791/GJ)] (2) As evaluated by McDaniel in 2011 (3) As evaluated by McDaniel at year end 2010 and mechanically updated for reserves additions (4) 10 % ownership interest with option to increase to 40%

Operating Profile

• Conventional Shallow Gas

• Mannville Heavy Oil

• Viking/Colorado Shallow Shale Gas

• Bitumen – Near Cold Flow – Panny Bluesky

• Bitumen – Thermal – Liege Carbonates

• Warwick Gas Storage

Eastern Alberta

• West Central Multi-Zone Liquids-Rich Gas

• Edson Wilrich

• Elmworth Montney Deep Basin

• Tight Oil and Gas Exploration

• TriOil Resources (2%) New Ventures

7

Entrepreneurial Approach to Value Creation

Invest For Growth • Edson Liquids-rich Wilrich Gas • Eastern Alberta Heavy Oil

Sustainable Cash Flow Generators

• Legacy Conventional Shallow Gas in Northeast & East Central Alberta

SHAREHOLDER VALUE

Optimize and Advance • Warwick Gas Storage • Elmworth Montney Gas • Viking/Colorado Shale Gas • Panny Bitumen

Exposure to Emerging Technologies

• NE Alberta Bitumen in Carbonates • Tight Oil & Gas Exploration • GOB Technical Solutions

TriOil Resources (2%)

OPTION VALUE

DIVERSIFYING GROWTH

STRATEGIES

CASH FLOW GENERATORS

+

=

+

+

+

8

9

1. Grow Oil and NGL Production Profitably through Capital Investment in 2 Key Commodity-Diversifying Priorities

Mannville heavy oil Wilrich liquids-rich gas

2. Restore Healthy Balance Sheet Dividend suspension Net Dispositions of $75 to $150 million Repay PMT.DB.C in June in cash Capital program funded within cash flow

3. Manage downside risks Decrease costs Protect cash flow Maintain optionality for debt management

4. Advance assessment of high impact opportunities with risk-

managed investment Viking/Colorado Panny Bitumen Mannville heavy oil waterflood/EOR

Focused plan to weather bottom of gas price cycle and thrive in transition

TOP 4 Strategic Priorities – 2012

Assets and Operations

11

Base Legacy Assets – Conventional Shallow Gas

Belly River

Viking

Grand Rapids

Lower Mannville

Pre Cretaceous Unconformity

Extensive inventory to minimize production declines at industry-leading capital efficiencies

East Central and Northeast Alberta

Cretaceous and Devonian sweet shallow gas

65% of production base

Base declines < 20%

Multiple stacked zones and play types

~700 uphole recompletions awaiting depletion of producing zones Low cost production and reserves adds (<$10,000/BOE/d;

<$1.00/Mcf)

Typically ~150 recompletions per year

380+ new drill prospects Historical drilling success > 90%

Seismic definition and step out of infrastructure drive prospects to drill ready

Multi-zone drills generally convert to reserves in 1 or 2 zones with additional zones captured as uphole completions in prospect inventory

~10 -20 new drills per year - best return and strategic only

Average well $0.4 MM D C & E

Risked IP 300 Mcf/d; EUR 0.3 Bcf

(<$25,000/BOE/d; <$1.77/Mcf)

Diversifying Growth Strategies

‘Chosen Key Priorities’

KC

F

GG

G

G

E

G

JF

G

E

G

IE

CU

IJI

EU

EJ

SUGU

E

GU

J

EU

J

SUEI

U SUEUM

UDU

G

LD

G

G

G

G

LLF

LFLU CULF

LFL

FUUUUUFF

FLF

G

EEUIU

EUEUEUEUEUIU

SU

SU

G

E US U

E US UE

UI US

U

SUE U

DU

EU

EU

EU

EUE

UE

UE

U

E UE

UE UM

UJ

USUEUSUEU

SUSUEUIUEU

SUF

F

IUEU

EUSUS

SEUEUIU

GIU

SU

CUEU

SUSU

SUIU

F

IU

F

S USU

G

F

L

F

GF

F

F

F

F

F

G

F

F

C

LF

F

F

F

G

FC

F

GF

G

F

F

F

F

F

F

F

F

IUFU

F

FE

G

F

F

F

F

F

F

F

F

F

F

F

G

F

F

GFF

F

LD

FG

F

F

L

F

LF

F

G

F

F

G

F

CD

LL

FA

KF

FAF

FFF

L

FK

LL

L

LF

G

LLGG

F

G

G

K

K

FC

G

KC

F

G

G

FGG

LLLL

L

F

L

L

LC

LCK

L

EV

LLAFL

L

JK

L

CC

FF

LL

LL

L

CUFU

A V

E

I V

FC

G

F

C

LG

FF

FALK

G

G

DV

G

F

G V

GV

G

D

V

E V

DV

G

D V

KK

D V

G

D V

KU

LFA

F

V

FAA

C

G

CUFU

A V

GULUFU

G

JKG

G

G

G

GC

G

KV

GULULU

FU

G

K

V

LL

G

G

G

CCCCCCCCGCK

DV

LFFFJLF

G

LU

G

G

KK

G

KCKKK

LF

G

GJLK

F

FV

G

LKF

KV

G

G

G

KF

G

JL

KK

KFC

GG

DV

GUFU

LLK

CGCC

FK

FA

LFK

G

G

GCC

CC

CC

L

L

F

GUCUGUCU

G

KF

G

LKK

V

G

LLG

G

G

F

AA

G

K

F

GJE

CG

EU

G

EU SUSIU

LF

EUSUEUEEUIUEUESEUEUISEU

SUE UEUSUIUEUEV

IU

GVEU SU SUEUSUEU

EUSU EUE

U

EUEU

SUEU

IU

SUIU

EULU

S

IKKEUEU

G

D

EUS

E

IU

EIUSU

EIU

EUEUIUIUE USU

SUEU

SUSU

EUIUEU

SU

I USUI U

G

EU

S U

IU

EUI

U EU

EU EU

EU

EU

EU

E U

IU

I U

SU

EU

S U

EUS

U

SUSUSUEUS U

SU

LFA

EUSU

G

IUEU

EUEUS

UDEUISU

EU

SU

JU

G

IUI

U IU

EU

SU

GUSU

SU

SU

SUSU

IU

EU

EUEU

EU

GDUI

UIU

EU

F

EU

EU

SU

SU

GK

EU

MESUI U

SDU

EUE

IUSEU

EU

SUIU

SU

SUSU

SUEUE U

IU

GUEUI

UL

G

EU

IUEUIUE UE U

EU

LU

E UEUS U

EU

S

SUS US

UEU

GU

SUS

USUS UE U

E U

EU

G

EUEEU

E

CU

IG

L

F

KGK

JG

EL

GG

G

LF

E

L

L

JU

KFG

K

G

KFCF

LLG

EU

EUEUEU

EU

L

EUDLEUEU

G

K

SUEUSU

GJLGEU

C

LJ

EU

G

F

G

FKCLF

CKJK

GU

G

F

G

K

K

F

K

G

F

G

SJSESE

GJ

S

G

ES

GF

J

FG

SE

E

S

SU

EI

S

I

EUS

E

ES

SE

EUSE

E

E

EM

EU

SE

S

EUS

S

E

ES

E

ES

F

SEU

F

E

E

SE

E

E

S

S

S

S

SE

EUMIM

S

E

E

E

SE

EU

EU

E

E

E

G

SE

E

E

S

S

ES

S

EU

E

EUS

F

ES

E

SE

S

E

ES

E

E

E

ES

JE

S

IDS

JD

E

E

E

S

SS

SESE

S

E

EUESESEV

S

F

EE

E

S

S

GS

E

E

J

E

FA

E

G

LGES

S

M

S

E

F

E

EJE

G

ES

M

S

S

G

E

G

SE

E

SE

E

ES

ES

F

GFA

SES

E

E

EEUEEU

G

KF

F

G

F

FA

F

V

GFA

VF

F

F

VF

F

IUFEUSU

F

IUSUEUSUEU

SU

IU SUEU

F

F

F

SU SU EU

F

F

F

EUSUUEUGUEUIUESUSUUSUUEUSUSUEU

F

F

EUE US US UE UE

U

F

I UE

UE US US

US

USUEUEUEUSUSUEU

F

EUIU

SU

F

F

G

GU

EU

G

DU SU

FV

KU

EU

GU

IUSUEUSUEUEUAAAIUCAUAUAUCUAUEU

SUEUEU

SU EU

SU

EU EU

SU

GU

EU

J

G

UIU

GU

IUEU

SU

SU

E U

SU

EU

EU

SUEUSU

EU

SUSUEU

E U

EU

D

U

EU SUE

U

G

SUS

EU

C UA U

GU

EU

EUD

EUEU

UU

SU

SU

SU

EUEU

EUI

UEU

IU

EEE

IU

SU

SU

E

D

E

U

EU

U

EU

SU

EU

SU

J

EU

EU

EU

EU

SU

EUE

U

SUEU

SU

EU

SUSU

EU

EU

EU

E

EU

E

U

EU

E

DE

EU

SU

U

EUEU

IU

S

EUD

EU

U

J

SU

SU

EU

EU

S U

SU

SUEU

S UE U

D

U

EUSUSU

EU

EUEU

EUEUEU

SU

S

EUSU

E UE U

D

DUE U

GU

SU

SUSUEUEU

S

USU

SU

EU

S U

EU

EU

SUE U

EU

EME UEU

DUE U

EU

EU

DUE UFGUEUEEUEUSEUSU

S

UDU

E

E

E

EJ

SE

E

E

S

F

S

SE

EESESEUG

E U

G

SEEEU

EU

F

EU

LU

E

EUSUGU

LKL

E UGU

CU

LG

F

F

F

G

FV F

F

G

LGC

F

F

F

F

F

G

F

G

EU

G

SUF

V

EUSU EUE

UIU

L

F

SUSUEUSUIU

F

F

F

EU

EUEUSUI

GUGU

DU

F

S

F

SUSU

EUEUSUEUEU

SUEU

EUE

UEU

L

FA

F

F

F

F

F

L

G

F

GF

G

G

C

GGGF

C

G

F

GF

KF

LK

L

G

L

GK

C

FA

FF

LLCF

G

GC

FCC

CCCCCCCC

G

CC

GCF

C

F

LL

FFF

LC

CG

CG

G

G

G

F

FC

LFG

G

FF

F

GG

C

G

CF

KF

G

G

F

KF

FCKK

FC

G

F

G

K

KG

G

F

F

CA

J

FC

C

G

GC

JGLGG

JGFF

G

KK

LUKUKU

K

G

FK

KK

G

G

CV CV

KUCU

CKK

G

G

G

F

LLKK

KKC

G

GU

G

C

F

G

KKC

G

G

G

KAK

G

GKGG

G

C V

KF

G

J

G

GCC

G

K

L

L

G

C

KUAULLAFFFACCG

G

GCCKF

E

V

LLAAAC

GLKK

LKGL

E

V

CKK

G

FK

GJFE

V

E

L

E

V

G

EFC

E

V

G

FF

G

G

C

E

V

K

E

V

FUFU

FA

G

E

V

L

ICF

F

GU

C

E

V

E V

FAA

EV

G

F

FU FU

G

LF

KUAU

EL

LF

G

FUCU

KUFUKU

G

GULULU

FU

FUKUFU

G

G

CV

G

GGFA

K

GUFU

G

G

FF

KUFU

AV

LLGAF

GC

C UFUJF

G

KKCF

GUGU

JLF

GUFUFU

FA

G

FF

LF

KU

KC

IKLF

JG

JLKF

F

C

EVAVAV

LF

EV

GGFF

GF

G

DLFKC

LLLFF

G

G

FF

LF

G

LLKF

G

G

KFLK

LLL

G

F

LKFE

KF

LLCCC

EU

G

JLKCE

EV

I

V

G

JC

LFF

CVEV

I

V

FLG

D

V

LKCE

JF

JLK

G

F

GG

E V

GGGCF

FUAU

E VC V

E

JKF

LL

G

JLG

CK

E V

MK

F

KF

F

GGGGF

GUGUFUAU

E

LL

JLLFE

G

C V

E V

C V

E V

LLFKF

FUFU

EU

LULULULUCU

G

ELLGC

JFK

K

KF

L

FA

I

AV

GF

L

G

LLL

A V

GF

KCF

LLLLLC

LKF

F

LCFA

LLJ

LFK

LF

F

LLGKGC

FA

GU

KU

KU

FU

G

LULUFUCUCU

GG

LL

GUFU

K

FA

F

LK

C

G

LL

GKKCC

G

K

GC

G

KKLK

LLGL

G

LFF

G

LUAUFU

LLLCFLUFU

GFLL

LL

C

LF

F

LL

FCCFF

F

FA

FF

FUGUF

GC

KF

C

G

LL

FKF

G

G

GGK

G

GL

FFF

LLLK

CF

LL

KLA

GG

KF

CF

G

KK

C

G

G

LL

G

LLCGG

G

G

G

G

G

G

FC

L

GL

G

F

LFG

GG

GF

LGF

GGCCCCCCCCK

K

GG

G

GGG

LLLLL

L

KC

FU

L

LF

JJFJ

GGLC

LF

C

GKF

G

E

G

SEESE

D

SA

ME

I

JJ

S

G

E

G

S

AEEG

E

I

G

E

ES

S

E

GEE

J

G

ES

ES

S

ES

G

E

SE

J

S

J

E

E

GGJUGU

S

E

S

S

E

C

D

E

M

E

JG

E

E

GUMUGJ

S

JE

GJ

G

GSE

SE

J

K

S

ESE

ES

E

E

EU

JJ

S

E

E

S

E

JJ

S

JG

J

J

JGJM

E

E

E

S

S

MMM

S

G

E

GMU

E

E

E

G

EU

JJ

S

S

ES

J

E

E

E

SESE

S

SEEU

E

U

EU

EGS

MESEM

E

EUSEU

EUDE

SSJS

SE

E

IS

E

MM

J

SGGE

EJ

EU

S

S

E

E

S

S

EE

E U

E U

G

E

G

S

S

E

S

EM

EU

E

G

E USE

ES

SE

E

E

ES

S

S

S

E

ME

LEM

E

DMDM

EU

E

S

S

D

EU

I

EU

EU

EU

S

SESE

E

E

EU

ES

S

ESESUM

E

UEU

E

E

M

GSS

SMES

E

EU

EU

E

ESU

JS

S

E

SU

L

S

E

S

SU

G

SE

EE

E

S

M

LL

E

SE

S

S

DES

SESE

E

IUS

S

G

E

ES

F

E

ESE

EI

S

E

FF

J

F

F

GU

GU

G

J

EF

F

J

LF

FCF

FG

C

V

F

K

GF

G

GU

F

G

F

G

G

F

V

F

CF

F

GF

LLF

F

LUFU

C

F

L

G

G

GU

F

V

F

F

F

F

F

FC

F

F

G

G

FF

F

G

KF

GU

G

GG

F

G

G

F

G

F

G

KG

F

G

LLCF

G

GFG

G

F

GLF

CF

F

G

C

G

LGF

GJG

F V

LL

LL

VVVVVVVV

G

FUCU

G

GC

G

F

K

F

G

F

F

F

C

G

F

AF

LL

C

K

JL

T47

T48

T49

T50

T51

T52

T47

T48

T49

T50

T51

T52

R7W4R8R9R10

R7W4R8R9R10

File: BW_East_Mannville Conv Heavy ODatum: NAD27 Projection: Stereographic Center: N53.28294 W111.20866 Created in AccuMap™, a product of IHS

Geographically synergistic with shallow gas assets

Production established from 10 Mannville pools

6 Lloydminister, 3 Sparky, 1 Basal Quartz

> 122 MMbbl Original Oil in Place (1)

> 6 MMbbl @ 5% recovery factory

Production > 3,000 bbl/d exit for Q1 2012

Low cost HZ development

HZ ~ $1,050 K /well

No stimulations required

Average initial rate over 100 bbl/d

Evaluating downspacing, waterflood and other enhanced recovery

Additional exploration ongoing

15-20 additional exploration prospects identified and captured

Extensive in-house 3D & 2D seismic

123,000 net acres of lands

13

Eastern Alberta - Conventional Heavy Oil

Inventory includes 200 locations at varying stages of drill readiness

~3D coverage

Sparky

Lloyd

Mannville

Basal Quartz

(1) Independent Resource Evaluation

0

50

100

150

200

250

300

0 5,0

00

10

,00

0

15

,00

0

20

,00

0

25

,00

0

30

,00

0

35

,00

0

40

,00

0R

ate

(b

bl/

d)

Cumulative Prod (bbl)

Sparky PoolINDIVIDUAL PROD vs TYPE CURVE

00/14-33-050-08W4/0

00/15-33-050-08W4/0

00/13-33-050-08W4

02/13-33-050-08W4

00/16-32-050-08W4

02/16-32-050-08W4

03/04-04-051-08W4/0

02/04-04-051-08W4/0

00/01-28-050-08W4/0

00/02-28-050-08W4/0

00/03-28-050-08W4/0

Risked Type Curve

Sparky ‘Type Curve’

Average initial rate over 100 bbl/d

14

Eastern Daily Oil Production

Performance exceeding expectations Approaching 3,000 bbl/d

15

1,000

1,500

2,000

2,500

3,000

3,500

Dec-11 Feb-12 Apr-12 May-12 Jul-12 Aug-12 Oct-12 Dec-12 Jan-13

Oil

b

bl/

d

Eastern Daily Oil Production

Actual

Current Estimate

Notes: (1) Q1 2012 Capital Expenditures for Mannville Heavy Oil is $20 MM of $34MM total (2) Full year 2012 Mannville Heavy Oil Capital Expenditures estimated at $42MM of $65MM total budget

Assumptions

Pricing $105/bbl WTI; $35/bbl differential = $70 Lloydminister heavy blend

Operating Costs $10.50/BOE (first year), $29/BOE (lifetime)

Type Curve IP 70 bbl/d, One year exit rate 37 bbl/d

Reserves 75 Mbbl per well

Royalties 5% for first 18 months; 10% thereafter

Growing low-risk heavy oil drilling inventory in excess of 100 drill-ready locations

Mannville Heavy Oil Value Potential

16

Projected Economics per Drilling Location

Capital (D,C & T) $1.05 MM

NPV @ 10 % $1.05 MM BT

ROR 95% BT

F&D $14.46/ BOE

Capital Efficiency ~$21,950 BOE/d

Recycle Ratio 3.9

Oil over shakers while drilling HZ wellsite Sparky development pad

Edson Wilrich Liquids – Rich Gas

17

Horizontal Well

Q1 2012 Wells

Edson 16-10 Compressor Capacity 30 MMcf/d

1-34 New Compressor Capacity 12 MMcf/d

Edson

West

Edson

Doubled Wilrich land position in 2011... 80 net locations and growing 36 bbl/MMcf NGLs

Q1 drill tested 15.5 MMcfd @ 14 MPa

To Edson third – party deep cut plant

Assumptions

Pricing $4/Mcf; $95/bbl WTI = $66.30/bbl NGLs ($3/Mcf; $105/bbl WTI = $76.50/bbl NGLs)

Operating Costs $6.45/BOE

Well Depth 3,900 M HZ; 2,400 TVD

Type Curve IP 3.5 MMcf/d, One year exit rate 1.85 MMcf/d 36 bbls/MMcf NGL’s/condensate

Reserves 3 Bcfe per well

Royalties 5% new well royalty rate for 500 MMscf

Risk Unrisked

Projected Economics per Drilling Location

Capital (D,C & T) $4.9 MM

NPV @ 10 % $3.6 MM BT ($2.3 MM BT)

ROR 53% BT (37% BT)

F&D $10.47/ BOE

Capital Efficiency <$12,000 BOE/d

Recycle Ratio 2.54 (2.19)

Flare while drilling 13-5 Wilrich HZ

West Edson Wilrich exceeding type curve Higher pressure with higher initial rates and expected reserves and better economics

Preparing to Frac 13-5 Wilrich HZ

Wilrich Value Potential

Pad completion in section 5

18

Other Diversifying Growth Strategies

‘Optimize and Advance’

20

Area development plan likely will include new plant construction

Perpetual Locations Montney Producers Perpetual Lands

ELMWORTH

92 Gross Sections of Montney Exposure

50/50 Joint Venture with Tourmaline

Reserves and Contingent Resource

Close to 4 Tcf OGIP (internal estimate)

>1 Tcf gross OGIP in Montney B recorded by McDaniel

42 Bcfe net P+P reserves booked

136 Bcfe net best estimate additional contingent resource

34 gross (17 net) sections not yet evaluated (SW Wapiti Block)

Technical Viability of Play Confirmed

Over 20 competitor wells drilled & tested ; further drilling ongoing

IP (1 month) of offset HZ wells 3 to 6 MMcf/d

3 Perpetual-interest wells tested 6 to 8 MMcf/d/well

Recombined free liquids and NGLs ~ 20 bbl/MMcf condensate plus 25 to 45 bbl/MMcf NGLs (processing – dependent)

2% H2S

West Central Alberta Resource Projects – Elmworth Montney

Elmworth Montney Prospect Inventory

21

>150 Identified Future Undeveloped Locations

C

B

A

Drilled & Flow Tested

Drilled & Tested

Initial Development POD

Initial Development 50 MMcf/d gross POD

Gross Startup Activities per Development Pod 12 Upper Montney wells Compression Separation Dehydration Facilities Associated P/L Gathering Systems

Gross Start Up Capital $100 – 120 million 12 wells drilled plus facilities in Year 1 Drill to fill ~ 4-6 gross wells/year thereafter Total of ~50 wells per POD

Drilled & Tested

POD 2

POD 3

Resource Projects - Viking / Colorado Tight Shallow Gas

22

Vast Tight Shallow Gas Play

Booked Reserves (Viking Only)

4 Bcf P+P Producing 14 Bcf P+P Developed Non-Producing 80 Bcf P+P Undeveloped 903 Vertical drills in future development

capital Average 138 MMcf/well gross

Prospect Inventory

Over 475 sections of land with where unbooked Viking potential has been identified

2011

Advanced detailed technical study

Special core analyses

Gas in Place analysis, production inflow and fracture modeling

Phase 1 of pilot plan evaluating fracture performance through recompletions

2012

Phase 2 of pilot plan evaluating fracture performance through recompletions

Incorporate learnings from pilot into plan for commercial trials and full scale execution

Belly River Play Fairway Cardium/ Colorado Wells Perpetual Lands Viking Proved Undeveloped Viking Probable Undeveloped Viking Proven Non-Producing Prospect Inventory 5 Yr

Bitumen Lands

23

Perpetual OS Leases

Fireflood Projects

CSS Projects

Primary Projects

Oil Pipelines

SAGD Projects

Electric Heaters

527 net sections (335,979 net acres) of oil sand leases

7 discrete project areas

Various formation targets and ultimate recovery methods

2011 Q1 Activity Tested 4 project areas - South

Liege, Hoole, and Panny

9 verticals; 1 Hz

24

Bitumen – Panny Bluesky

Excellent reservoir quality in Bluesky homogeneous shoreface

sand facies

2010/11 Vertical Locations

2010/11 Horizontal Locations

8m Bitumen

10m Bitumen

Roads Natural Gas Pipeline Oil Well Effluent Pipeline Perpetual Gas Plant Perpetual Oil Sands Rights Other Perpetual Lands

Q1 2011

Drilled 3 vertical, 1 HZ to evaluate possibility of cold flow in greater Panny area

Established low rate flow without solvent or thermal assistance

Average pay thickness 11 m

Fairly low viscosity bitumen

~15,000 cp @ 25 C

Resource Assessment (McDaniel) 755 MMbbl Discovered OBIP (P50)

132 MMbbl Contingent Resource (P50) assigned utilizing horizontal cyclic steam

Future drilling planned targeting contingent resource expansion

Submitted application for pilot test

Bitumen – Liege Carbonates

Q1 2011 OV Wells Perpetual Oil Sand Leases Leduc Reef

GROSMONT NET BITUMEN

10 - 20 m

20 – 30 m

>30 m

T95

T94

T93

T92

T91

T90

R19 W4 R 20 R 21 R 22

T89

3 Grosmont carbonate / Leduc wells drilled in Q1 2011 to evaluate resource

Stacking of 3 Grosmont units; > 30 m pay

Leduc reef facies present and bitumen saturated in places; geologically complex

P50 Resource Assessment (McDaniel)

2,327MM bbl bitumen in place (Undiscovered plus Discovered)

66 MM bbl Contingent Resource assigned

400 MM bbl Prospective Resource assigned

20% recovery factor applied using SAGD as ‘technology under development’

Excellent reservoir quality vuggy porosity in Grosmont

25

Diversification Strategy Summary

0%

6%

12%

18%

24%

30%

36%

42%

48%

0

50,000

100,000

150,000

200,000

2007 2008 2009 2010 2011 2012F

% D

ive

rsif

yin

g G

row

th v

s Le

gacy

An

nu

al A

ve

rage

Pro

du

ctio

n (M

cfe

/d)

Growth vs Legacy Assets

Legacy Shallow Gas Production GOB Deemed Production Diversifying Growth Assets 2007 Dispositions2008 Dispositions 2009 Dispositions2010 Dispositions 2011 Dispositions2012 Dispositions % Diversifying Growth Assets (Excluding Deemed)

27

Diversification Strategy - Resource Growth Plays

8 fold increase in production from resource-style growth assets in two years

28

Diversification Strategy - Oil and Liquids Production

260% increase in oil and liquids production in two years Trend to continue in 2012

29

Cash Flow Diversification - Oil and Liquids Revenue

270% increase in oil and liquids revenue in two years Trend to continue in 2012

Asset Divestiture Program

31

Asset Divestiture Program

Q1 through Q3 2011: Disposition proceeds totaled $38 million

Non-core properties in northeast and west central Alberta and undeveloped land in the Pembina area

November 2011: Announced non-core asset divestiture program targeting proceeds of $75 - $150 million for debt reduction and June debenture repayment

Q4 2011 to Q1 2012: $66.8 million in further non-core dispositions closed

Production sold ~8 MMcf/d and 390 bbl/d oil and NGL (1,900 boe/d - 85% gas)

April 5, 2012: Announced further transactions for total proceeds of $84.3 million expected to close by April 30, 2012

No production impact

Reduced 2012 cash flow by $2 – 3 million

Continue to pursue additional asset sales

Target Exceeded - $151.1 MM proceeds from dispositions

Grass Roots Gas Storage Development of existing depleted gas pool

‘Test Cycle’ Injection: Q2/Q3 2010

Facility Construction Q2-Q4 2010

> 200 MMcf/d withdrawal capacity

‘Test Cycle’ Withdrawal: Q1 2011 7.8 Bcf

Second Cycle: Q2 2011 – Q1 2012 17 Bcf

Commercial ‘Park and Loan’ business

Cycle 3 working gas capacity set at 17 Bcf

2012 full scale operations forecast operating cash flow $11 MM

Expansion opportunities with additional capital

30 to 50 year life

Warwick Gas Storage

32

Non-depleting, long life, diversified asset

Warwick Glauconitic -Nisku A Pool

WGSI Storage Leases

• 40 Bcf Storage Reservoir − 10 Bcf base reserves cushion gas in place − 5 -11 Bcf additional operating cushion − Up to 25 Bcf potential working gas capacity

• 1.2 to 1.5 cycle facility

1 mi

WGSI Leases Well Site Pad Compressor Facility Pipeline Horizontal Wells H1 2011 Hz Well H2 2011 Hz Wells

4-18

5-18

2-19

Warwick Joint Venture Arrangement

Sale of 90% partnership interest in Warwick Gas Storage

Perpetual to manage and operate asset for annual fee

For a period of one year post closing, Perpetual has option for one-time election to

repurchase up to an additional 30% equity interest, resulting in Perpetual owning

between 10% and 40% of WGSI partnership

Option purchase price reflects prorata disposition price less distributed cash

flow plus adjustments

One year option allows Perpetual to evaluate balance sheet and other capital

investment opportunities and further assess natural gas market, reservoir

performance and expansion project before making election to increase

ownership

33

33

Balance Sheet

Balance Sheet

35

~75% of proforma total net debt has term of almost 3 years or greater

• Current Net Bank Debt (proforma dispositions): ~$20 million Revised borrowing base on credit facility - $140 million

Next semi-annual redetermination prior to October 31, 2012

• Senior Unsecured Notes: $150 million Coupon Rate - 8.75%; Maturity date - March 2018

• Convertible Debentures: $235 million Repayable with bank debt or with equity at Perpetual discretion

Expect PMT.DB.C to be repaid in cash at June 30, 2012

$160 million effectively represents long term debt with 2015 maturities

TSX Symbol

Amount Outstanding

Coupon Rate

Conversion Price

Maturity Date

5 Day Weighted

Avg. Trading Price

PMT.DB.C $ 74.9 million 6.50% $ 14.20 June 30, 2012 $ 92.00

PMT.DB.D $ 100.0 million 7.25% $ 7.50 January 31, 2015 $ 80.00

PMT.DB.E $ 60.0 million 7.00% $ 7.00 December 31, 2015 $ 80.00

• Total Net Debt (proforma dispositions): ~$405 million

Balance Sheet

36

Debt reduction through asset base repositioning

Managing Downside Risk

Price Risk Management Strategy

• Enhance or protect funds flow and balance sheet

• Enhance or protect the economics of an acquisition as prices vary from those forecast

• Enhance or protect capital program economics

• Capitalize on perceived market anomalies

38

(1) Futures price reflects forward market prices as at April 5, 2012 (2) Calculated using 2012 Q2-Q4 estimated gas production of 131,000 GJ/d, including actual and gas over bitumen deemed

projected production

Natural Gas Hedging

Type of Contract

Term Volumes at AECO

(GJ/day)

Price

($/GJ)

AECO/NYMEX Futures Price

($/GJ) (1)

% of 2012E

Q2-Q4

Production (2)

AECO Fixed Price Apr – Dec 2012 44,000 $2.60 $1.92 33%

AECO Fixed Price Apr – Oct 2012 10,000 $2.85 $1.76 6%

AECO Fixed Price Jan – Dec 2012 45,250 $3.73 $1.92 35%

AECO Fixed Price Jan – Dec 2013 25,000 $3.24 $2.85 19%

Gas Price Protection for 74% of April – December Forecast Production at $3.13/GJ Mark to Market Value of Natural Gas Forward Sales ~ $25 MM for Remainder of 2012

39

(1) Calculated using 2012 Q2 -Q4estimated oil and NGL production of 3,450 bbl/d

Crude Oil Hedging

Type of Contract

Term

Volumes at WTI

(bbl/day)

Floor Price

($US/bbl)

Ceiling Price

($US/bbl)

% of 2012E

Production (3)

Collar Jan – Dec 2012 500 $82.00 $91.00 14%

Collar Jan – Dec 2012 500 $80.00 $89.00 14%

Collar Jan – Dec 2012 500 $85.00 $97.00 14%

Collar Jan – Dec 2012 500 $90.00 $109.00 14%

Period Total Jan – Dec 2012 2,000 $84.25 $96.50 57%

Type of Contract

Term

Volumes at WTI

(bbl/day)

Strike Price

($US/bbl)

Call Jan – Dec 2013 1,000 $95.00

Call Jan – Dec 2013 1,000 $105.00

Call Jan – Dec 2014 2,000 $105.00

Type of Contract

Term

Volumes

(bbl/day)

Price

($US/bbl)

WCS differential Jan – Dec 2012 400 $(17.35)

WCS differential Mar – Dec 2012 500 $(28.75)

40 2012 oil prices volatility managed with collars and fixed WCS differentials

Outlook

Conventional Gas Activity,

$0.4

Wilrich Liquids-Rich

Gas, $7.1

Other Deep Basin, $1.0

Mannville Heavy Oil,

$21.4

Unconventional Viking/Colorado

, $0.1

Land/Seismic, $2.9

Maintenance Capital, $1.3

Facility Optimization,

$1.5

42

Q1 2012 Capital Budget

Q1 2012 Capital Budget: $34 MM

Heavily weighted to oil and liquids-rich gas

Drill, Complete and Tie-ins: $29 MM

Heavy Oil – 20 gross (20 net) heavy oil wells

Wilrich – 3 gross (2.5 net)

Recompletions / Workovers: $2 MM

12 recompletions/workovers & tie ins

Seismic and Land: $3 MM

Maintenance , Abandonment & Reclamation: $1 MM

35 gross abandonments

Target Production Additions

~8.2 MMcfe/d (1st 12 month average)

Budget Capital Efficiency ~$26,076/flowing BOE/d

Close to 100% million targeting oil and liquids rich gas projects

43

2012 Full Year Capital Scenario

Project Activity Objective 2012 Capex

Indicative Play

Specific F&D

($/Boe)

Mannville Heavy Oil Drill 20 gross (20 net) Mannville wells

Significantly increase oil

production and cash flow 20 20.90

Wilrich Drill 3 gross (2.5 net) Wilrich wells

Grow liquids rich and cash flow

production 7 18.00

Other Deep Basin Drill 1 Well Evaluate new oil play 1 35.20

Land and Seismic Increase holding on key plays 3

Other

12 Recompletions and Workovers, 35

Abandonments, 3 Overhaul projects 3

Total Q1 34

Mannville Heavy Oil Drill 19 gross Mannville wells

Significantly increase oil

production and cash flow 22 20.90

Wilrich/Fahler Drill 1 well

Increase inventory of

opportunities 1 18.00

Other Deep Basin Drill 2 Wells, Evaluate new oil play 4 35.20

Other 21Workover and recompletions 4 --

4 Abandonments/EH&S projects

1 Facilities overhauls --

Land and seismic --

Potential Q2-Q4 31

Total 65

Total Capital: $65 MM

Vast majority of capital directed to Mannville Heavy Oil Modest Wilrich spending to earn lands and evaluate West Edson

Diversification Strategy 75% Heavy Oil;

25% Wilrich

45

Diversification Strategy Scenario 75% Heavy Oil/25% Wilrich Capital 2012 - 2015

Assumptions •Oil and gas strip pricing @ March 23, 2012 • $60MM capex for 2012; $75MM in 2013; $125MM in 2014-15 • 75% Mannville; 25% Wilrich post-2012 at current type curve assumptions and economics • Pro forma for Warwick gas storage joint venture arrangement at 10% PMT retention • $75MM 2012 debentures and $160 MM of 2015 debentures repaid in cash

Excess Cash Flow for Debt

Repayment or Reinvestment

46

Diversification Strategy Scenario Forward Market Price Strip Assumptions 2012 - 2015

47

Diversification Strategy Scenario 75% Heavy Oil/25% Wilrich Capital 2012 - 2015

Assumptions •Oil and gas strip pricing @ March 23, 2012 • $60MM capex for 2012; $75MM in 2013; $125MM in 2014-15 • 75% Mannville; 25% Wilrich post-2012 at current type curve assumptions and economics • Pro forma for Warwick gas storage joint venture arrangement at 10% PMT retention • $75MM 2012 debentures and $160 MM of 2015 debentures repaid in cash

48

Diversification Strategy Scenario – 100% Heavy Oil Year end Debt 2012 - 1015

Assumptions •Oil and gas strip pricing @ March 23, 2012 • $60MM capex for 2012; $75MM in 2013; $125MM in 2014-15 • 75% Mannville; 25% Wilrich post-2012 at current type curve assumptions and economics • Pro forma for Warwick gas storage joint venture arrangement at 10% PMT retention • $75MM 2012 debentures and $160 MM of 2015 debentures repaid in cash

49

Sum of the Parts

PMT Trading at Less than 1/3 reserve-based ‘blowdown’ NAV

All project values @ McDaniel January 1, 2012 oil and gas price forecasts

Investment Thesis

50

Asset base repositioning for oil and liquids-focused opportunities successful

Edson Wilrich in full scale development phase

Conventional heavy oil development and low exposure exploration very promising

Evolving commodity mix materially growing future funds flow

High impact value potential from long term resource plays

Elmworth Montney resource identified and scoping development scenarios

Material bitumen in place and contingent resource defined at Panny and Liege

Vast Viking/Colorado shallow shale gas fairway undergoing evaluation

Deleveraged for June 2012 convertible debenture repayment

75% of proforma debt has term beyond 2014 providing flexibility

Growing cash flow through diversification strategy will improve debt to cash flow ratios

Multiple ‘levers’ available to further manage balance sheet

Extremely limited exposure to further gas price weakness in 2012

Tremendous leverage to any gas price cycle recovery in 2013 and beyond

Every $0.50 per Mcf = $20 million of annual funds flow

Strategically setting in place the inter-locking pieces for a strong growth strategy

3200, 605 – 5 Avenue SW

Calgary, Alberta CANADA T2P 3H5

800.811.5522 TOLL FREE

403.269.4400 PHONE

403.269.4444 FAX

info@perpetualenergyinc.com EMAIL

www.perpetualenergyinc.com WEB

FOR ADDITIONAL INFORMATION:

Susan L. Riddell Rose President & CEO Cameron R. Sebastian Vice President, Finance & CFO Claire Rosehill Business and Investor Relations Analyst