Year-End Webcast

Presentation

March 6, 2014

Forward-Looking Statements

1

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 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 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.

1

DIVERSIFIED

RESOURCE – STYLE

GROWTH – ORIENTED

ENTREPRENEURIAL

EXPLORER, PRODUCER & MARKETER

Perpetual Energy – TSX:PMT

BUILT TO GROW BUILT TO PROSPER BUILT TO LAST 2

Common shares outstanding 148.5 million Management ownership 25.34%

Share price (March 5th 2014) $ 1.36

30 day weighted average daily trading volume ~ 595,000 shares/day

Market capitalization $ 202 million

Total Net Debt $ 377 million Net bank debt $ 67 million

Convertible debentures $ 160 million

Senior unsecured notes $ 150 million

Enterprise value $ 579 million

Conventional

Shallow Gas

Distributing Trust

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

Operating Profile

3

• 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

4 Spectrum of Opportunities to Invest In Through Variable Commodity Cycles

Invest For

Growth

• Edson Wilrich

• Greater Edson

Multi-zone

• Deep Basin

Exploration

Maximize

Cash Flow

• Eastern Alberta

Conventional

• Viking/Colorado

Shallow Shale

Gas

Invest For

Growth

• Mannville

• Mannville EOR

• Heavy Oil

Exploration

HEAVY OIL LIQUIDS-

RICH GAS

SHALLOW

GAS BITUMEN OTHER

Advance and

Optimize For

Value

• Panny Bluesky

• Marten Hills

Clearwater

• Liege Grosmont

and Leduc

• Other

Advance and

Optimize For

Value

• Warwick Gas

Storage (30%)

• GOB Technical

Solutions

• Exploration

Portfolio Management Strategy

5 Entrepreneurial 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

PROVEN

DIVERSIFYING

GROWTH STRATEGIES

CASH FLOW

GENERATORS

Commodity Diversification

6 Oil and NGL’s 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

0%

5%

10%

15%

20%

25%

-

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

2009 2010 2011 2012 2013 2014E

Pe

rce

nta

ge o

f to

tal p

rod

uct

ion

(%

)

Oil

and

NG

L P

rod

uct

ion

(b

bl/

d)

NGL Sales

Oil Sales

% Oil and NGL of Total Production

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

$0

$20

$40

$60

$80

$100

$120

2009 2010 2011 2012 2013 2014E

Re

ven

ue

($

MM

)

Oil and NGL Revenue

Oil and NGL % of Revenue

Oil and NGL Production

Asset Base Transformation

7 Strong Production Growth Profile in Diversifying Assets

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

2014 Focus Grow Deep Basin production

Optimize heavy oil business

Mitigate declines in shallow gas

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2009 2010 2011 2012 2013 2014E

Pro

du

ctio

n (

% o

f to

tal)

Oil

NGL

Deep Basin

E. Shallow Gas

-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

2009 2010 2011 2012 2013 2014E

Gro

wth

Ass

et

Pro

du

ctio

n (

bb

l/d

)

Mannville Heavy Oil

Deep Basin Gas

Deep Basin NGL

2013 Annual Results

2013 Top 5 Strategic Priorities

9 Strategic Priorities Focus Our Activities

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

2013 Top 5 Strategic Priorities

10 Significant Scope for Increased Reserves and Value

with Infill Drilling, Waterfloods and Possible Polymer Floods

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

2013 Top 5 Strategic Priorities

11 Expanded Capital Program Delivered Substantial Increases in

Production, Reserves, Revenue and Value

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

2013 Top 5 Strategic Priorities

12 Long Term, High Impact Projects Advancing with Modest Capital Spending

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 l to evaluate prospective condensate-rich Duvernay acreage

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

2013 Top 5 Strategic Priorities

13 Myriad of Strategies Successfully Employed to Manage Downside Risk

Cash Flow Growth Accomplished with Debt Reduction

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

2013 Top 5 Strategic Priorities

14 Modest Shallow Gas Program Ready to Execute in 2014

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

15 Capital Focused on Proven Diversifying Plays

Total 2013 Wells 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

Total Capital: $96.7

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

2013 Full Year Capital Spending Summary

2013 Production Highlights

16 Commodity 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%

Oil & NGL production 412 bbl/d to 3,860 bbl/d, a 12% from 2012 levels • Mannville heavy oil grew 17%

• 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)

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

2013 Funds Flow

17

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 Prod’n $9.7 MM

Hedging Gains $24.3 MM

Gas Prod’n $10.2 MM

Gas Storage $0.8 MM

Royalties $6.3 MM

Cash Costs $9.3 MM

Funds Flow $9.4 MM

Cash Costs, excluding royalties, Down $9.3 MM from 2012

2013 Balance Sheet Reconciliation

18 E&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

19 Reserves in Key Diversifying Growth Plays Increased 51% Year over Year

Mannville Heavy Oil & 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/PUD

2PNP/2PUD PDP

2PDP

PNP/PUD

2PNP/2PUD

PDP

2PDP

PNP/PUD 2PNP/2PUD

Reserve Value Distribution

20

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

Value of Key Diversifying Growth Plays Increased 33% Year over Year

Mannville Heavy Oil & Deep Basin now 70% of P+P Reserve Value, up from 53% from 2012

Total NPV 10 = $622 million

PDP

2PDP

PNP/PUD

2PNP/2PUD

PDP

2PDP

PNP/PUD

2PNP/2PUD

PDP

2PDP

PNP/PUD 2PNP/2PUD

2014 Top 5 Strategic Priorities

21 Strategic Priorities Focus Our Activities

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

Investment Thesis

23 2014 Capital Focused on Proven Diversifying Plays

Q1 2014

Wells Capital

Q2-Q4 2014

Wells Capital

Total

Wells Capital

West Central Deep

Basin

3 gross

(2.0 net) $18 MM

Up to 7 (3.5

net) $21-$26MM

Up to 10

(5.5 net) $39-$44MM

Mannville Heavy Oil

11 gross

(9.7 net) $13 MM

Up to 12

(8.3 net) $11-$14MM

Up to 23 (18

net) $24-$27MM

Eastern Shallow Gas

Recompletions

/

Workovers/

Facility

Optimization

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

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

Total Capital: $70 – 80 MM

2014 Capital Spending Plan

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

Gas Price Risk Management

24

Type of Contract Term Volumes

(GJ/d)

Fixed Price

($/GJ)

Futures

Price(1)

($/GJ)

% of 2013

Natural Gas

Production(2)

AECO Fixed

Price Financial Apr – Jun 2014 20,825 $4.01 $4.36 18%

AECO Fixed

Price Financial Apr – Oct 2014 26,100 $4.02 $4.35 23%

AECO Fixed

Price Physical Apr – Oct 2014 5,275 $4.06 $4.35 5%

AECO Fixed

Price Financial Apr – Dec 2014 10,000 $3.71 $4.39 9%

AECO Fixed

Price Financial Jul – Dec 2014 22,500 $4.25 $4.41 19%

AECO Basis

Financial Apr – Oct 2014 7,500 ($0.48) ($0.37) 6%

1) Mar 5, 2014 forward prices

2) Calculated using Q4 2013 actual and deemed gas production of 109.8 MMcf/d

Gas Price Risk Management Strategies Primarily for Q1-Q3 2014 and AECO Basis

Oil Price Risk Management

25

Type of

Contract

Term Volumes

(bbl/d)

Fixed or

Floor Price

($/bbl)

Ceiling Price

($/GJ)

($/bbl)

Futures

Price(1)

($/bbl)

% of 2013

Oil & NGL

Production(2)

WTI collars Mar – Dec 2014 1,500 US $86.67 US $95.15 US $96.90 43%

WTI collars Calendar 2015 1,000 CAD $87.50 CAD $95.50 US $88.30 28%

WTI Calls Mar - Dec 2014 2,000 US $105.00 - US $96.90 57%

WTI Calls Calendar 2015 1,500 US $100.00 - US 88.30 43%

WTI Fixed

Price Mar - Jun 2014 750 US $90.00 - US $99.70 21%

WTI Fixed

Price Mar - Dec 2014 250 US $90.00 - US $96.90 7%

WTI-WCS

Differential Apr - Dec 2014 2,000 US ($21.64) - US ($21.90) 57%

1) Mar 5, 2014 forward prices

2) Calculated using Q4 2013 Oil and NGL production of 3,509 bbl/d

More Duration and Volume to Oil Price Risk Management Strategies

Strong Annual Growth

26 Year over Year Growth Forecast on Top Priorities

2013 (versus 2012)

Oil and NGL production growth of 12%

Mannville oil production growth of 24%

Resource-style 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

Sum of the Parts

27 Trading at ~1/2 of ‘Reserve-Based’ Net Asset Value

-$500.00

-$250.00

$0.00

$250.00

$500.00

$750.00

$1,000.00

$1,250.00

Liabilities Assets Risked Assets UnRisked

NP

V 8

% (

$M

M)

Warwick Gas Storage

Viking/Colorado Shallow ShaleGasConventional Shallow Gas

Edson/West Edson

Bitumen

Mannville Heavy Oil

Gas Over Bitumen

Proved + Probable Developed

Proved + ProbableUndevelopedHedge Book

Bank Debt

Senior Notes

Convertiable Debentures

Net ARO

Unrisked NAV $7.18/Share

Reserve Based NAV(1) $3.06/Share

$6.80

$5.10

$3.40

$1.70

$0

$8.50

Risked NAV $4.90 /Share

-$1.70

-$3.40

NAV Per Share

(1) Includes $180 MM fair market value of undeveloped land based on third party land value assessment

(2) WGS LP valued at proportionate acquisition value in all scenarios

PMT Investment Thesis

28 Spectrum of Opportunity to Grow and Prosper

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

>80% of debt has term into 2015 providing flexibility

Asset dispositions and growing cash flow improving debt to cash flow ratios

60% drawn on credit facility

Multiple ‘levers’ available to further manage balance sheet

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

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.

Important Information about the Presentation

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

FOR ADDITIONAL INFORMATION:

Susan L. Riddell Rose

President & CEO

Cameron R. Sebastian

Vice President, Finance & CFO

perpetualenergyinc.com