A G M P R E S E N TAT I O N | M A R C H 2 4 , 2 0 1 6

BOLD IDEAS

FOR ENERGY

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," "2015 through 2016" 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 managementstrategies which include the transitioning from shallow gas assets to resource-style, growth orientated oil and NGL assets and divestitures to optimize value anddecrease debt; projected economics for various projects; future capital expenditure levels; expected compliance with credit facility covenants in 2015 and 2016 the topstrategic priorities for 2015 and beyond. These statements are not guarantees of future performance and are subject to certain risks, uncertainties and other factors,some of which are beyond our control and are difficult to predict. Therefore, actual outcomes and results may differ materially from what is expressed or forecastedin 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 orotherwise.

Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are: inaccuracies in the estimated timingand amount of future production of natural gas and oil due to numerous factors including permit delays or restrictions, weather, equipment failures, delays or lack ofavailability, unexpected subsurface or geologic conditions, lack of capital, increases in the costs of rented or contracted equipment, increases in labor costs, volumesof oil or gas greater or lesser than anticipated, and changes in applicable regulations and laws; unexpected problems with wells or other equipment, unexpectedchanges in operating costs and other expenses, including utilities, labor, transportation, well and oil field services, taxes, permit fees, regulatory compliance and othercosts 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 toraise capital; variances in cash flow, liquidity and financial position; a significant reduction in our bank credit facility's borrowing base; availability of funds from thecapital markets and under our back credit facility; our level of indebtedness; the ability of financial counterparties to perform or fulfill their obligations under existingagreements; write downs of our asset carrying values and oil and gas property impairment; the discovery of previously unknown environmental issues; changes in ourbusiness and financial strategy; inaccuracies in estimating the amount, nature and timing of capital expenditures, including future finding and development costs; theinability 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 givenmarket 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 weatherlimiting or damaging operations and the occurrence of natural disasters such as fires, floods, hurricanes, earthquakes and other catastrophic events and naturaldisasters; the high-risk nature of drilling and producing natural gas and oil, including blow-outs, surface caterings, fires, explosions; the competitiveness of alternateenergy sources or product substitutes; technological developments; changes in governmental regulation of the natural gas and oil industry potentially leading toincreased costs and limited development opportunities; changes in governmental regulation of derivatives; developments in natural gas-producing and oil-producingcountries potentially having significant effects on the price of gas and oil; the effects of changed accounting rules under generally accepted accounting principles andIFRS promulgated by rule-setting bodies; the amount of future abandonment and reclamation costs, asset retirement and environmental obligations; expectedrealization of gas over bitumen royalty adjustments; inability to execute strategic plans and realize projected economics, expectations and objectives for futureoperations and price risk management strategies; and the other risk factors identified in our most recent financial statements and management's discussion andanalysis and Annual Informational Form and our other filings on SEDAR. Unpredictable or unknown factors not discussed herein also could have material adverseeffects on our business and operations and on the forward-looking statements contained herein. Also included in this presentation are estimates of Perpetual'sconsolidated net debt and 2015 funds flow, which are based on the various assumptions as to production levels, capital expenditures, and other assumptions(including price assumptions for natural gas and oil) and the effects of the West Edson property disposition. To the extent any such estimate constitutes a financialoutlook, it was approved by management and the Board of Directors of Perpetual on March 12, 2015 and is included to provide readers with an understanding ofPerpetual's anticipated funds flows based on the capital expenditure and other assumptions described herein and readers are cautioned that the information may notbe appropriate for other purposes.

2

Forward Looking Statements

Perpetual Energy Inc.

3

Common shares o/s (1) 1,047 million

Management ownership ~49%

Share price $ 0.07

Market capitalization $ 73 million

Total net debt (2) $ 150 million

Net bank debt (2) $ 32 million

Financing arrangement (3) $ 21 million

Senior unsecured notes $ 275 million

TOU Shares 6.25 million @ $28.50/share

($ 178 million)

Enterprise value $ 223 million

(1) Pro-forma share consolidation at 20:1 = 52.4 million(2) Estimated current bank debt, net of working capital; includes reserve-based facility and

TOU share-based margin loan(3) Settle amount at November 2016 maturity; Secured by 1 million of the TOU Shares

4

Diversified portfolio for value creation

Spectrum of opportunities to optimize value through variable commodity cycles

Mannville

Mannville EOR

Heavy Oil Exploration

HEAVY OIL

Edson Wilrich

Greater Edson Multi-zone

Edson Secondary Zones

Deep Basin Exploration

LIQUIDS-RICH GAS

Eastern Alberta Conventional

Viking / Colorado Shallow Shale Gas

SHALLOW GAS

BITUMEN

Panny Bluesky

Liege Grosmont & Leduc

Other

OTHER

Warwick Gas Storage

Waskahigan Duvernay

GOB Technical Solutions

Tight Oil and Gas Exploration

OTHER

5

• 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 & gas exploration

Deep Basin

Operating profile

LIQUIDS-RICH GAS East Edson

Other Deep Basin

SHALLOW GASLegacy conventional assets, Tight shallow gas

HEAVY OILMannville

BITUMENPanny, Liege, Other

GAS STORAGE

Warwick

Production (1) 19,706 boe/d

Natural Gas 104 MMcf/d

Oil and NGL 2,337 bbl/d

P+P Reserves (2) 77.8 MMboe

Reserve to Production Ratio (P+P) (RLI) (2) 12 Years

Bitumen (3) 279 MMbbl

Warwick Gas Storage Capacity (gross) (4) 19.1 Bcf

Tourmaline Oil Corp. Shares – 6.25 million (5) ~180 million

(1) Year Ended December 31 2015

(2) Year Ended December 31 2015

(3) 425 sections at year end 2015; Internal contingent resource estimate

(4) 30% ownership interest

(5) March 22, 2016 market price of $28.50/share

6

Portfolio management strategy 2016

Entrepreneurial approach to value creation

Re-invest to mitigate declines

Edson liquids-rich gas

Mannville heavy oil Waterflood

Maximize Cash & Preserve Value

Conventional shallow gas

Warwick Gas Storage

Mannville heavy oil

Optimize & Advance

Mannville heavy oil EOR

Viking/Colorado shale gas

Waskahigan Duvernay

Tight oil & gas exploration

Bitumen – Panny / Liege

MEDIUM AND LONG TERM

VALUE STRATEGIES

PROVENDIVERSIFYING

GROWTH STRATEGIES

CASH FLOW GENERATORS

7

2016 Top four strategic priorities

Strategic priorities focus our activities

1. Reduce debt & restore cash flow

2. Grow value & scope of Greater Edson liquids-rich gas

3. Maximize value potential of Eastern Alberta assets

4. Advance high impact opportunities

KEY PRIORITY #1

REDUCE DEBT AND RESTORE CASH FLOW

9

2015 Asset Transactions

West Edson swap $ 258 million

6.75 million TOU shares

6.25 million remaining

Closed April 1/2015; MTM ~$180 MM

Fee Simple land sale $ 21 million

Royalties & seismic

Closed April 10/2015

Recapitalization Transactions

Convertible Debenture Settlement

Issued 230 million PMT shares $ 35 million

Closed Dec 31/2015

Rights Offering $ 25 million

Issued 665 million PMT shares

Closed Jan 18/2016

2016 Asset Transactions

Oil Sands leases $ 6.1 million

37 sections

Closed March 2016

Debt reduction

Targeting additional asset sales for further debt reduction

~$150 MM(1)

(1) Rights Offering & TOU Share Appreciation Estimate March 2016

10

West Edson transaction summary

Desire to retain maximum exposure

Swap of West Edson property for 6.75 million Tourmaline Shares

•24 MMboe of reserves 7.2 MMboe (29%) proved and probable developed producing 16.8 MMboe undeveloped reserves requiring ~$124.5 million of future development capital over 7- 10 years

•5,750 boe/d of production (95% gas)

•2015 negative funds flow impact of ~$15 - $20 million

Transaction Rationale

•Swap for exposure to upside potential in West Edson but also well-funded Alberta Deep Basin and BC Montney portfolio through TOU shares

• Improve liquidity

•Strengthen financial position and optionality Bolsters ability to manage future debt obligations

Allows flexibility to fund capital program to capture inherent value in East Edson and other high impact assets

Enhanced lending value for TOU shares relative to West Edson reserves (20% proved producing)

Improves cost and access to capital to pursue new strategic initiatives

•Enhance ability to manage downside risk in low commodity price environment

•Neutral to reserve-based NAV discounted at 10%

•Reduce net debt, considering TOU shares as a direct offset

Current Holdings 6.25 million shares @ MTM value of $180 million

Extend

Maturities

• Bank debt maturities extended to October 31, 2016

• Revised financial covenants provide increased flexibility and stability

• $35 million reduction of debt through settlement of Convertible Debentures through issuance of PMT Common Shares

Recapitalization transactions

Debt

Reduction

Preserve

Asset Base to

Maintain Value

Potential

• Allows us to maintain attractive current assets and operations

• Full upside to Tourmaline shares preserved

Improve

Liquidity

• $25 million of new equity capital through Rights Offering

• $18 million from New Financing Arrangement increases liquidity through securitization of 1 million Tourmaline shares

Recapitalization transactions enhance balance sheet strength

12

Post-Recapitalization balance sheet

Net Bank Debt: ~$32 million(1)

• Borrowing base on credit facility - $62 million $20 million reserve-based loan

– Opened up for redetermination due to falling commodity prices – March 2016

– Historically calculated net of $40 million grind for senior notes

$42 million margin loan secured by 5.25 million TOU shares– Single one time only draw (no revolving feature)

– Interest rate = prime + 4.75% (~6.45%)

– Loan to value ratio = 33.3% (3.0 times margin coverage)

– Term margin loan matures on October 31, 2016

Senior Unsecured Debt: Face Value $275 million; Market Value ~$150 million

New Financing Arrangement: $21 million

• Established downside protection on 1 million TOU Shares to enhance collateral lending value

• Carrying amount $18 million - All costs prepaid

• Matures November 2016

TOU Shares: 6.25 million shares @ $28.50/share = $180 million

Total Debt Net of TOU Shares: ~$150 million

TOU Shares provide significant offset to future debt obligations

(1) Current Estimate March 2016

SeriesAmount

OutstandingCoupon

RateMaturity

Date

Current Trading

PriceCurrent

YieldMarket Value

8.75% 2018 $150 million 8.75% March 2018 $55.00 63.3% $82.5

8.75% 2019 $125 million 8.75% July 2019 $53.00 38.7% $66.3

13

2015/2016 Capital spending

• 2015 Excludes abandonment and reclamation spending of $ 7.2 Million• 2016 Excludes abandonment and reclamation spending estimate of $ 2.5 Million

2015

Activity Capital

2016

Q1

2016

Q2-Q4

2016

Total

West Central

Liquids-Rich Gas

6 gross (4.5 net) wells

West Wolf Facility$ 67.5 MM

$ 5 MM

1 gross

(1 net well)

$ 2.3 MM$ 7.3 MM

Mannville Heavy OilWaterflood

facilities $ 1.4 MM $ 1 MM $ 0.1 $ 0.2 MM

Eastern Shallow Gas and

Other

Recompletions/

Workovers/

Optimization

$ 1.9 MM $ 0.1 MM $ 0.7 MM $ 0.8 MM

Panny Pilot2 gross

(2.0 net)$ 4.6 MM $ 0.0 MM $ 0.0 MM

Total $ 75.4 MM $ 5.2 MM $ 3.1 MM $ 8.3 MM

Adjustable capital program focused on mitigating declines and net cash flow generation

KEY PRIORITY #2

GROW VALUE AND SCOPE OF GREATER

EDSON LIQUIDS-RICH GAS

16-10 CompressorCapacity 30 MMcf/d

To Rosevear Plant (15% WI)

West Wolf Lake10-3 Gas Plant

Capacity 45 MMcf/d

Pipeline To EdsonDeep Cut Plant

Edson Wilrich Liquids–rich gas

PERPETUAL

Pre-2014 Drill

2014 Drill

2015 Q1 Drill

2016 Q1 Drill (1)

2016 Q3/Q4 Drill (3)

2017 Proposed Drill (6)

East Edson JV Lands

Inventory of 138 gross (123 net) undrilled locations 87 gross (79 net) booked in reserve report

16

East Edson type curves

Dec 31,

Average well consistently beats McDaniel Type Curve, even though rates for most wells were curtailed pending new plant commissioning in early July 2015, and expansion in September 2015

Projected Economics per SW Drilling Location

Capital (D,C & T) $ 4.8 MM

NPV @ 10 % $ 2.4 MM

ROR 33% BT

F&D $ 8.50 / boe

Capital Efficiency $9,000 boe/d

Payout 2.6 Years

Recycle Ratio 1.7

Assumptions (McDaniel YE 2015)

Year 1 Pricing $2.55/ GJ (Aeco); $32.23/ bbl NGL

Operating Costs

$2.72/ boe (first year)

Well Depth 4,600 M HZ; 2,500 TVD

Type CurveIP 6.5 MMcf/d1 year exit rate 1.8 MMcf/d11.5 bbl/MMcf NGL/condensate

2P Reserves 3.4 Bcfe per well

McDaniel SW Type CurveMcDaniel NE Type Curve

18 JV wells drilled to complete all near term commitments, with 3 remaining wells required by 2023. Well performance above type curves.

17Production from West Edson swap for TOU shares effectively replaced upon start-up of new East Edson Plant in July 2015

Greater Edson production growth

0

10

20

30

40

50

60

70

80

90

Jan-14 Mar-14 May-14 Jul-14 Sep-14 Nov-14 Jan-15 Mar-15 May-15 Jul-15 Sep-15 Nov-15 Jan-16 Mar-16

Gas

Rat

e (

Mm

cf/d

)

Greater Edson Daily Production

Edson Ansell

TCPL Restrictions

40% net production growth in 2014

•Driven by West Edson expansion from 15 to 30 MMcf/d net

• Ramp up to fill existing East Edson facilities with JV drilling

• 30 MMcf/d by year end 2014

136% net production growth in 2015

•Growth despite swap of West Edson (30 MMcf/d net plus associated liquids) effective April 1

• Constructed new 30 MMcf/d East Edson plant onstream July 2015

• Expanded East Edson plant to 45 MMcf/d September 2015

• Infrastructure ownership drove low Q4 op costs of $2.46 per boe

•Drilled to fill East Edson facilities and transportation contracts

30 MMcf/d in H1 ramping up to 60 MMcf/d in H2

Improved results required 5 less wells in 2015 than forecast to achieve capacity through the year

Preserving Value in 2016 low gas price environment

• Current capital plan includes 1 drill and complete

Continued growth potential in 2017 through 2018

•Drill to fill existing infrastructure as appropriate

East Edson – Up to 75 MMcfe/d capacity (full year effect)

• Potential further expansion at East Edson plant of additional 15 MMcfe/d to take area capacity to 90 MMcfe/d

Secondary Viking, Notikewin and Fahler horizontal development potential supported by 3D seismic exploration

18

Greater Edson liquids-rich gas play performance

Infrastructure and inventory in place for continued growth

East Edson

West Edson

-

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

-

2,000

4,000

6,000

8,000

10,000

12,000

14,000

2010 2011 2012 2013 2014 2015 2016E

Cu

mu

lati

ve P

rod

uct

ion

(M

Bo

e)

Bo

e/d

KEY PRIORITY #3

MAXIMIZE VALUE OF EASTERN ALBERTA ASSETS

20

Eastern Alberta – Conventional heavy oil

Capital focused on waterflood implementation in 5 main pools

Drilling deferred due to low oil prices to preserve development inventory

8 Producing Mannville pools *

• 6 Lloyd, 1 Sparky, 1 Basal Quartz

• > 136 MMbbl Original Oil in Place

• > 6 MMbbl @ 5% recovery factor

• Current Production ~ 1,100 bbl/d

Low cost HZ development• $1 - $1.2 MM single or dual lateral HZ well

• Average initial rate ~80 bbl/d

2015 Capital activity

• $2.2 MM of waterflood expansion

• Additional injection conversions in 3 pools

• Source water conversion to supply additional water

• Facility and pipeline expansion

2016 Capital activity plans

• Up to $1.2 MM of waterflood expansion

• Additional 4 injection conversions

• Facility and pipeline expansion to optimize operating costs

Mannville

Current Injectors

2016 Recommendations

* 6 of 8 pools shown

21

Mannville heavy oil value potential

Highly profitable in oil price recovery

Projected Economics Per Well

Lloyd Sparky

Capital (D,C & T) $1.2 MM $1.2 MM

NPV @ 10 % $1.6 MM $0.8 MM

ROR ~ 200% ~ 95%

F&D $13.50 / Boe $20.50 / Boe

Payout 0.7 Year 1.2 Year

Capital Efficiency ~$15,000/Boe/d ~$25,000/Boe/d

Recycle Ratio 3.0 2.7

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 WellLloyd IP 120 bbl/d to 75 bbl/d after year 1Sparky IP 85 bbl/d to 44 bbl/d after year 1

2P Reserves90 Mbbl per Lloyd well60 Mbbl per Sparky well

Royalties5% for first 18 months on Crown; variable on Freehold

22

Waterflood and enhanced oil recovery

Waterflood injection optimization through 2015 showing increasing oil response

Working Interest 66.7%

OOIP: 38 MMbbl Cum Prod’n + McDaniel P+P: 1.5 MMbbl (4%

recovery factor) technical recovery

19 Horizontals drilled to date

11 infill locations remain

Implementing Waterflood 7 injectors converted in 2013/2014

1 injection conversion 2016-2017

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

6 m OIL PAY

Sparky Mid Sand

> 24 % DENSITY POROSITY

Mannville I2IWaterflood Pool

0

200

400

600

800

1/1/2012 1/1/2013 1/1/2014 1/1/2015 1/1/2016 1/1/2017 1/1/2018

Oil

bb

l/d

Upper Mannville I2I Waterflood Update

Oil Rate

Oil Base Forecast

Internal Forecast

McDaniel YE 2015

Base Forecast

Wat

er

Inje

ctio

n S

tart

Internal Forecast McDaniel YE 2015Actuals

23

Early waterflood response

Positive initial waterflood response in Mannville B pool supports progressing full waterflood expansion

0

40

80

120

160

200

1/1/2013 1/1/2014 1/1/2015 1/1/2016 1/1/2017 1/1/2018

Oil

Rat

e, b

bl/

d

NE portion Mannville B Pool - Lower Channel Sand

Oil RateOil Base ForecastMcDaniel YE2015Internal Forecast

Actuals

Base Forecast

Water Injection Start

Internal Forecast McDaniel YE 2015

0

40

80

120

160

1/1/2013 1/1/2014 1/1/2015 1/1/2016 1/1/2017 1/1/2018

Oil

Rat

e, b

bl/

d

Single pattern Mannville B Pool - Regional Lloyd Sand

Oil RateOil Base ForecastMcDaniel YE 2015Internal Forecast

Actuals

BaseForecast

Water Injection Start

Internal Forecast McDaniel YE 2015

24

Waterflood and enhanced oil recovery scope

Large scope for increased reserves and value through waterfloods and possible polymer floods

Select Pools OOIP

(MMbbl)

Cumulativeproduction to YE 2015

(MMbbl)

P+P Reserves booked at YE 2015(MMbbl)

Implied Recovery

Factor

(%)

Expected Primary

Recovery(5-8%)(MMbbl)

Potential withSecondary Recovery

and EOR(10-15%)(MMbbl)

Sparky I2I 35 0.7 0.7 4.3% 1.8 – 2.8 3.5 – 5.3

Upper Mannville B (1) 77 2.5 1.6 5.3% 3.8 – 6.2 7.7 – 11.5

Upper Mannville T8T 10 0.2 0.6 7.6% 0.5 – 0.8 1.0 – 1.4

Total 122 3.4 2.9 5.2% 6.1 – 9.8 12.2 - 18.2

4 to 6 X

(1) Reflects former Upper Mann A & B pools currently merged – AER

25

Conventional shallow gas

Reduced asset retirement obligation by close to $50 million in 2015 through multi-faceted, full life cycle operating approach

Belly River

Viking

Grand Rapids

Lower Mannville

Pre Cretaceous Unconformity

Legacy asset base characteristics

Northeast and East Central Alberta

Cretaceous and Devonian sweet shallow gas < 800m

Current production ~ 50 MMcf/d

Base declines < 10-15%

Multiple stacked zones and play types

Extensive plant and pipeline infrastructure with material unutilized capacity

Low base royalty rate of ~ 5% at <$5/Mcf

High fixed operating costs driven by municipal taxes and large number of low volume wells

Netbacks highly leveraged to natural gas prices

Operational Focus

Facility optimization projects, workovers and uphole recompletions payout in months

Low cost production and reserves adds (<$10,000/boe/d; <$1.00/Mcf)

Drive fixed and variable operating cost reductions

Metering, municipal taxes, scaled-back operational approach, ARO

Prospecting for tight reservoirs in high resource potential traps that now can be exploited with horizontal wells and multi-stage frac technologies

26

Viking/Colorado shallow shale gas

>130 TCF Resource In Place

OGIP estimated average 16 Bcf/section

200-300m gas saturated shale section 6 prospective zones

Viking

Booked reserves 12 Bcf PNP booked in recompletions

Historical 2P reserves of 100+ Bcf removed from bookings due to price revisions

Proven development & capital commitment could drive substantial future bookings

Colorado Group

> 1 TCF potential recoverable resource HZ development at ~8+ wells / section

Over 1,200 net prospective sections

Extensive plant & pipeline infrastructure

Develop with Viking & Mannville tight sands to reduce costs & enhance economics

2015

Evaluated competitor activity to further refine frac design, performance & costs expectations

Encouraging in $3+ gas price environment

2016

Horizontal pilot ready to execute

Encouraging results from competitor operations

Full scale development improves netbacks on existing shallow gas operations

Belly River Play Fairway

Cardium/ Colorado Wells

Perpetual Lands

Historical Viking Reserves

Proved Undeveloped

Probable Undeveloped

Reserves Proven Non-Producing

Competitor horizontal drills

KEY PRIORITY #4

ADVANCE HIGH IMPACT OPPORTUNITIES

28

Warwick gas storage

Non-depleting, long life, diversifying assetCash flow growth potential as spreads normalize to historical levels

• 40 Bcf Storage Reservoir• Delta Pressure to 47 Bcf 10 Bcf base reserves cushion gas

in place Up to 25 Bcf potential working

gas capacity• 1.2 to 1.5 cycle facility

WGSI Leases

Well Site Pad

Storage Facility

Pipeline

Horizontal Wells

2012 Hz Wells

TCPL Pipeline

Commercial ‘Park and Loan’ business

30 to 50 year life

Grass Roots Development Existing depleted gas pool Facility Construction 2010

19 - 21.5 Bcf working gas capacity

Expansion Potential Delta pressuring to increase working gas to

24.5 Bcf with minimal incremental costs

30% Perpetual Interest

Manage WGS LP for annual fee

Diversified Cash Flow 2012 & 2013 ~$11 million/year gross

Electrical fire upset operations and reduced

cash flow in 2014 & 2015

2016 projected cash flow ~$10 million gross

29

Waskahigan Duvernay volatile oil play

Volatile oil/high liquids gas play proven prospective on PMT acreage

Monitoring test well & play development to evaluate costs and performance

AOC Farm-in: • Drilled & completed 16-36-63-25W5

• PMT retains 35% in 6 sections & 100% in 3.75 sections

• Land continued to 2019

16-36 Production• Onstream Dec 1, 2015

• Average daily production December

289 Bbl/d Condensate

277 Mcf/d Gas

• ~21 Bbl / MMcf C5+

• ~93 Bbl / MMcf C3/C4

• Downhole pump installation March 2016 to optimize production

Full Development Potential:• OOIP > 86 MMbbl (44 net)

• ~8 wells per section

• 64 gross (32 net) wells

PMT ( 35% WI)

PMT (100% WI)

AOC Drills

AOC Licenses

Apache Licenses

Chevron Drills

Chevron Licenses

CIOC Drills

Encana Drills

Encana Licenses

Duvernay Net Pay

Contour Interval = 5m

Simonette

Leduc Reef

16-36

Deep Valley

Gas Plant

Richer/Volatile

Oils

Leaner/Gas

Condensates

13-1Cum to date 84 MSTB Oil

(17 months)

396 net sections (253,000 net acres) of oil sand leases

Various formation targets and ultimate recovery methods

7 potential project areas with varying potential

Over 3 billion bbls OBIP independently recognized at Liege and Panny

278 MMbbl contingent resource

467 MMbbl additional prospective resource

Sold 37 net sections of select oil sands leases for $6.1 million in Q1 2016

30

Bitumen

Bitumen lands represent large resource in place and material option value

Panny

Ells

North & South Liege

Wabasca

Hoole

Perpetual OS Leases

Perpetual Panny Pilot

Experimental

Primary Projects

Thermal Projects

Other Projects

Major Oil Pipelines

Laricina Saleski

Carbonate Pilot

Athabasca Oil

Dover West Carb Pilot

Husky Saleski

Carbonate Pilot

CNRL

Cherpeta

CNRL

S. Brintnell

CNRL

S. Wabasca

CNRL

Wabasca N.

CNRL

Woodenhouse

Husky

Amadou

Husky

McMullen

Crescent Pt.

BrintnellHusky

McMullen Thermal Pilot

Sunshine

Harper

Sunshine

West Ells

CNRL

McLaren

Brion

Dover

Cavalier

Hoole

Koch

Muskwa

Sunshine

Thickwood

Marathon

Birchwood

OSUM

Sepiko Kesik

Prosper

Rigel

Sunshine

Legend Lake

Koch

DunkirkAndora

Sawn Lake

N. Alberta Oil

Sawn Lake

Grizzly

Thickwood

Cenovus

Pelican LakeCenovus

Pelican Lake Grand Rapids

Southern Pacific

STP McKay

CNRL

Brintnell

Black Pearl

Blackrod Pilot

Suncor Dover Demo

Suncor

MacKay River

Perpetual

Panny

LEAD Pilot

31

Bitumen – Panny Bluesky

Excellent reservoir quality in Bluesky homogeneous estuarine sand facies

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 at 25oC

• 50,000 cp at 11oC reservoir temp

• Highly mobile at ~70oC

Panny Bluesky Resource Assessment

• 755 MMbbl Discovered OBIP (McDaniel 2011)

• Reservoir simulation model supports >50% recovery factor

• Resource to support >25,000 bbl/d commercial project for 20 - 25 years

LEAD Pilot Phase 1 – now operating

• Phase 1 consists of a single horizontal well

• Heating commenced in October 2015

• First production in March 2015

• Production is exceeding expectations by >100%

• IETP funding reimburses 30% of all capital and operations costs

Experimenting with lower energy intensity extraction technologies than traditional steam-based thermal methods to mobilize bitumen

Panny LEAD Pilot

32

LEAD process technology pilot Low pressure electro-thermally assisted drive

Electrical heating cable with water injection for mobility and pressure support

First stage of pilot – single well Cyclic Heat Stimulation currently operating

Electrical resistive heating and production in a single horizontal well to validate reservoir flow model and heater technology

Two highly instrumented observation wells in close proximity to the horizontal heater well monitoring reservoir response

Commenced electrical heating in October 2015

First oil production in March 2016, currently exceeding cumulative oil production expectations by >100%

Second stage of pilot – an additional $20 to $30 million

Guided by first stage learnings

Initial 10,000 to 15,000 bbl/d development if pilot successful

Drilling-intensive technology allows for scalability without large upfront capital commitment of steam projects

Top Gas

Heaters / Injectors

Oil

Producer

LEAD Pilot Stage 2 Configuration

INVESTMENT THESIS

EXTREME VALUE DISCOUNT TO ASSET VALUE

LEVERAGED TO GAS PRICE RECOVERY

AND ‘BEST IN CLASS’ GAS E&P (TOU)

34

Sum of the parts

Trading materially below reserve-based net asset value

NAV• Year End 2015 reserves and inventory with market-to-market adjustments for TOU share

price appreciation, rights offering, March 2016 debt and share consolidation

(1) 6.25 million TOU shares @ $28.50/share(2)(3) Includes appreciation of TOU shares based on 12 month TOU consensus target price of $ 35.68/share

35

Key investment highlights

High Quality Assets

Asset base repositioning for resource-style and diversification successful

Edson Wilrich liquids-rich gas inventory well-defined

Mannville heavy oil delivering diversified cash flow with material secondary recovery potential

Prospects for short and long term growth from resource-style plays

Increasing percentage of higher netback production in asset mix

Exposed to premium asset base through TOU share ownership

Alberta Deep Basin, BC Montney & Peace River High Charlie Lake plays

Track Record of Operational Performance

Execution and operational excellence in chosen strategies

Multiple Levers to Manage Balance Sheet

80% of debt has term into 2018 and beyond

Multiple ‘levers’ available to manage debt obligations

Pursuing further asset dispositions to continue to reduce outright debt leverage

TOU shares provide offset for future debt obligations

Recapitalization transactions create modest liquidity to execute prudent capital spending program and survive commodity price collapse

Value

Trading below ‘Reserve-Based’ Net Asset Value through Equity Transaction Uncertainty

Net asset value materially connected to TOU share value at 50% of enterprise value

High impact value potential from medium to long term assets

Tremendous leverage to oil and gas price cycle recovery in 2016 and beyond

Spectrum of opportunities for value creation upon emergence from bottom of commodity price cycle

36

ADDITIONAL INFORMATION

Sue Riddell Rose President & CEO

Cam Sebastian Vice President, Finance & CFO

info@perpetualenergy.com EMAIL

800.811.5522 TOLL FREE

403.269.4400 PHONE

403.269.4444 FAX

3200, 605 – 5 Avenue SWCalgary, Alberta Canada T2P 3H5

W W W. P E R P E T U A L E N E R G Y I N C . C O M