C O R P O R AT E P R E S E N TAT I O N

S E P T E M B E R 2 0 1 7

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," and similar expressions are intended to identify such forward-looking statements. Such statements include, but are not limited to, statements pertaining to: Perpetual's spectrum of opportunities that can be optimized through variable commodity cycles and anticipated value creation arising from such opportunities; Perpetual's top strategic priorities including reducing debt and restoring cash flow, growing value and scope of greater Edson liquids-rich gas, maximizing value of Eastern Alberta assets and advancing high impact opportunities; targeting additional asset sales for further balance sheet improvement; anticipated benefits of waterflood projects; reserve and resource estimates; projected economics for various projects and expenditures; and future capital expenditure levels. 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 equity or debt 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 equity or debt 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 bank 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 ; the amount of future abandonment and reclamation costs, asset retirement and environmental obligations; 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

Forward Looking Statements

3

Financial Profile

Common Shares o/s (1) 59 million

Management ownership 46%

Share price (1) $ 1.30

Market capitalization $ 77 million

Net bank debt (2) $ 11 million

TOU share-based loan (3) $ 19 million

Term Loan (4) $ 35 million

Senior unsecured notes (2) $ 33 million

TOU Shares (1.67 million) (3) ($ 41 million)

Total net debt $ 57 million

Enterprise value $ 134 million

(1) Sept 7, 2017 market price; Fully diluted shares outstanding of 69.3 million includes 6.5 million warrants with an exercise price of $2.34/share

(2) Net bank debt, including net working capital estimated at June 30, 2017, adjusted for Q3 2017 financing transactions

(3) Loans secured by 1.67 MM Tourmaline Oil Corp. (TSX: “TOU”) shares; Market price Sept 7, 2017 $24.55/share

(4) Initial draw $35 million; Second draw of $10 million prior to November 30, 2017

Financial Profile

4

• Conventional shallow gas

• Mannville heavy oil

• Bitumen

• Viking/Colorado shallow shale gas

Eastern Alberta

• Edson Wilrich

• Multi-zone liquids-rich gas

• Tight oil & gas exploration

Deep Basin

LIQUIDS-RICH GAS East EdsonDeep Basin Other

SHALLOW GAS & OTHERConventional Misc.PannyTight Shallow Gas

HEAVY OILMannville

BITUMENPanny, Liege, Other

Asset Summary

Production (1) 11,400 boe/d

Natural Gas (84%) 58 MMcf/d

Oil and NGL (16%) 1,800 bbl/d

P+P Reserves (2) 61.3 MMboe

Reserve to Production Ratio (P+P) (RLI) (1) 15 Years

Bitumen (3) 399 MMbbl

Tourmaline Oil Corp. Shares – 1.67 million (4) $ 41 million

Operating Profile

(1) Production – August 2017

(2) Year end 2016

(3) Internal contingent resource estimate

(4) Market price of ~$24.55/TOU share Sept 7, 2017

5

High Graded Asset Base

Production base focused to East Edson Deep Basin and Mannville

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2011 2012 2013 2014 2015 2016

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Building a foundation of resource-style plays

Robust multi-zone inventory for profitable exploration and development

High working interest, operatorship and infrastructure control

Higher value sales mix

Liquids-rich gas

Higher heat content gas

Condensate & NGL sales

Heavy oil

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6Spectrum of opportunities to optimize value through variable commodity cycles

Short term investment as well as longer term value opportunities

• Mannville

• Mannville waterflood/EOR

• Heavy oil exploration

• Panny Bluesky

• Liege Grosmont & Leduc

• Bitumen land bank

• Mannville & Pannyconventional shallow gas

• Mannville Viking/Colorado shallow shale gas

• Tight conventional exploration

• Edson Wilrich

• Greater Edson secondary zones

• Columbia/Brazeau

• Deep Basin & Wilrichexploration

Liquids-Rich Gas

Shallow Gas

Heavy Oil

Bitumen

Diversified Portfolio for Value Creation

7Positioned to pursue profitable growth strategy

Grow Value of Greater Edson Liquids-Rich Gas

Optimize Value of Eastern Alberta Assets

Advance High Impact Opportunities

Optimize Balance Sheet For Growth

2017 Strategic Priorities

8

• Excludes 2017 ARO spending of up to $2.5

Financing transactions provide certainty to fund drilling program to restore production levels and grow funds flow

2017 Capital Spending

($ millions)

2017

H1

($ millions)

2017

H2 Forecast

($ millions)

2017

Total

($ millions)

West Central

Liquids-Rich Gas

$ 21

6 gross (6.0 net) drill

(complete 1 Q4 2016 drills

& 2 Q1 2017 drills)

$ 35 - $ 40

Up to 10 gross

(9.4 net) wells

(Complete 4 H1 2017 drills

& 7.4 net H2 2017 drills)

$ 56 - $ 61

Mannville Heavy Oil$ 4

4 gross (3.3 net) wells

$ 1

Waterflood conversions$ 5

Eastern Shallow Gas

$ 3

9 recompletions

1 gross (1.0 net) well &

complete 2

Viking/Colorado drills)

$ 1 $ 4

Total $ 28 $ 37 - $ 42 $ 65 - $ 70

9Forecast production per share growth of >60% over two years

Q4 2016 to Q4 2018

Capital plan to double production over 2 years

Funded capital program at forward strip prices

Front end loaded with ~60% exit rate production growth (Q4 2016 vs Q4 2017)

Q2 2018 step-up related to April 1, 2018 scheduled service date of additional TCPL firm transportation at East Edson

Forecast exit rate production per share growth of >60% over two years

Operations focus strengthens netbacks

East Edson unit operating costs <$3.00/boe

Expect PDP growth and 2P reserve replacement with cycling of East Edson technical reserves from prospect inventory; Net asset value created through improving capital efficiencies

Strong growth in funds flow and PDP value at current strip pricing to support expanding credit facility borrowing base capacity

Line of Sight Growth Plan

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Q4 2016 Q1 2017 Q2 2017 Q3 2017E Q4 2017E Q1 2018E Q2 2018E Q3 2018E Q4 2018E

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Forecast Production

Forecast Gas Production Forecast Oil & NGL

STRATEGIC PRIORITY #1

GROW VALUE OF GREATER EDSON LIQUIDS-RICH GAS

Inventory of 145 (134.7 net) Wilrich locations76 (73.7 net) booked in reserve report

Edson Wilrich Liquids–Rich Gas

PERPETUAL

Pre 20172017 Drilled to Date2017 Drills Remaining2018 Drills (10 wells)

H2 2017 Extended Reach Horizontals

underway

12

Projected Economics per SW Drilling Location

Capital (D,C & T) $ 4.3 MM

NPV @ 10 % $ 4.2 MM

ROR 60%

F&D $ 6.39 / boe

Capital Efficiency $7,200 boe/d

Payout 1.6 Years

Recycle Ratio 2.5

Assumptions (McDaniel YE 2016 - July1/17 Pricing)

Year 1 Pricing$2.64/ GJ (Aeco)$46.29/bbl NGL

Operating Costs

$1.86/ boe (first year)

Well Depth 4,350 M HZ; 2,625 TVD

Type CurveIP 7.0 MMcf/d1 year exit rate 2.0 MMcf/d11.75 bbl/MMcf NGL/condensate

2P Reserves 4.1 Bcfe per well

Strong performance drove McDaniel Year-End 2016 SW type curve IP up 8% while 2P recoverable reserves/type curve well increased by 21%

McDaniel SW Type CurveMcDaniel NW Type CurveMcDaniel NE Type Curve Average of wells since 2014

East Edson Type Curves

13Targeting further improvements in first 12 months capital efficiency to

<$7,000 per flowing boe/d

East Edson Wilrich Capital Efficiency

Continuous improvement in drilling & frac design driving strong capital efficiency and reduced future development capital

• H1 2017 - Monobore design proved up for type curve length wells

• H2 2017 - Evaluating:

Optimized monobore design with consistent rig program and longer laterals

Extended reach wells (“ERH”) targeting 2,200 to 3,000 meter lateral lengths

Dissolvable frac balls, eliminating costs to drill out balls and seats

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2010-2012 2012-2014 2014-2015 2015-2016 2016-2017 H2 2017EMonobore

H2 2017EERH

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/E&

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(M

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Capital Costs

Total Drilling and Completions and E&T Capital Average Cost Per Horizontal Length

$0

$2,000

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2010-2012 2012-2014 2014-2015 2015-2016 2016-2017 H2 2017EMonobore

H2 2017EERH

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–Fi

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/Bo

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Capital Efficiency

Capital Efficiency (First 12 Months)

14Increasing production driving top quartile operating cost structure of <$2.50/boe

Top Quartile Operating Cost Structure

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East Edson Operating Costs

Operating Costs Operating Costs ($/Boe)

2015: Growth driven by East Edson JV Royalty sale

•Ramp up to fill existing East Edson facilities

•Constructed new 30 MMcf/d West Wolf Lake plant on stream July 2015

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

•Drilled to fill East Edson facilities and transportation contracts

2016: Preserving Value in low gas price environment

•1 Q1 drill and Q3 frac & tie-in only

•Shut-in of negative cash flow sour volumes through third-party facility

2017: Drill to ramp up to existing plant & transport capacity

•1 rig Wilrich program drilling to fill existing infrastructure

60 MMcf/d plus NGL’s: 45 MMcf/d at West Wolf & 15 MMcf/d WI owner gas at Rosevear

2018: Grow to meet TCPL capacity growth

Add 15 MMcf/d compression capacity to match process at West Wolf plant

Continue 1 rig program to meet 78 MMcf/d transportation commitment by April 1 and maintain thereafter

2019: Sustain with Wilrich and Secondary Zone Evaluation

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

15Infrastructure and inventory in place for profitable growth

East Edson

West Edson Sold to Tourmaline April 1/15 for 6.75 million TOU shares estimated at $258 million (~5,750 Boe/d)

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2011 2012 2013 2014 2015 2016 2017E 2018E

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Greater Edson Liquids-Rich Gas Play Performance

16Plan to more than double production from Q4 2016 by April 2018 to match infrastructure capacity & transport

1) Includes GORR of 5.6 MMcf/d plus associated liquids to JV Partner

East Edson JV spending ramp up

West Edson Swap for TOU

Shares

East Edson New Plant start-up

Decision to defer capital spending

in 2016One rig drilling program commenced in Q4 2016

Greater Edson Production Growth

• 8 - 9 wells / year to sustain production at TCPL firm transportation of 78 MMcf/d

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Greater Edson Daily Production

East Edson Base Production West Edson Edson Forecast Production TCPL Transportation

STRATEGIC PRIORITY #2

OPTIMIZE VALUE OF EASTERN ALBERTA ASSETS

18

Eastern Alberta - Mannville

Drilling recommenced in Q1 2017 after 2 year hiatus for oil price recovery & waterflood assessment

9 Producing Mannville pools*

• 6 Lloyd, 2 Sparky, 1 Basal Quartz

• > 150 MMbbl Original Oil in Place

• > 7.5 MMbbl @ 5% recovery factor

• 4.5 MMbbl produced to date (3%)

• Current production ~1,000 boe/d

Low exposure HZ development• $0.8 – $0.9 MM DC&T per well

Capital costs reduced by 30% materially enhances profitability in current commodity price environment

• Average expected initial rate ~60 bbl/d

2017 Capital Program

• Drilled 4 heavy oil wells in Q1

3 exploratory / 1 development

May de-risk up to 29 potential inventory locations

2 exploratory gas wells drilled and being evaluated

Waterflood Expansion

• 1 injection conversion to be completed in Q4 2017 (booked in McDaniel)

*7 of 9 pools shown

19Large scope for increased reserves and value through continued waterflood management and potential polymer or other enhanced recovery processes

Select Pools Currently Under

Waterflood

OOIP

(MMbbl)

Cumulativeproduction to YE 2016

(MMbbl)

P+P Reserves booked at YE 2016

(MMbbl)

Implied Recovery

Factor

(%)

InternalRemaining

Recoverable (3)

(MMbbl)

Potential Remaining with Improved

Secondary Recovery and EOR (4)

(10-15%)(MMbbl)

Sparky I2I (1) 23 0.5 0.4 4% 0.6 1.8 – 3.0

Upper Mannville B (2) 35 1.5 0.9 7% 1.0 2.0 – 3.8

Upper Mannville T8T 10 0.3 0.4 7% 0.7 0.7 – 1.2

Total 68 2.3 1.7 6% 2.4 4.5 – 8.0

(1) Net working interest

(2) Mannville B Channel facies excluded from values as waterfloodresponse is limited thus far; Mannville B Channel OOIP is an incremental 41 MMbbl of oil and represents additional upside

(3) Internal remaining recoverable oil with full waterflood development and infill drilling

(4) Scope for enhanced recovery through improved waterfloodperformance and new technologies

Significant resource potential through

improved waterflood

recoveries & new technologies

Internal Estimate ~ 40% higher than booked

reserves

Waterflood and Enhanced Oil Recovery Scope

STRATEGIC PRIORITY #3

ADVANCE HIGH IMPACT OPPORTUNITIES

21

>885 Bcf Resource In Place

OGIP estimated average 5.9 Bcf/section

Viking

> 342 Bcf potential recoverable resource

Assumes HZ development at 2 wells/section

Probable opportunity to double to 4 wells/section

Booked reserves

1.3 Bcf PPNP booked in recompletions

Proven development & capital commitment could drive substantial future bookings

Colorado

> 245 Bcf potential recoverable resource

Assumes HZ development at 2 wells/section

Probable opportunity to double to 4 wells/section.

Over 150 net prospective sections

Plant & pipeline infrastructure

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

2015

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

Encouraging risk/reward at >$3/GJ gas price

Q4 2016/2017

Executing Viking/Colorado 2 well horizontal pilot

Fracture stimulation of wells has been deferred awaiting higher natural gas prices

Optionality on large resource in place

Risk-managed investment required to unlock technically for commercial development

Viking/ Colorado Hz Pilot

Competitor Hz Drills

Viking/Colorado Shallow Shale Gas

22

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 possible 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

• Phase 1 utilized a single horizontal well

• Heating commenced in October 2015

• First production in March 2016

• Cycle 2 May – September 2016

• Cycle 3 Solvent injection October 2016

• Cycle 4 December 2016 – May 2017

• IETP funding reimbursed 30% of all capital and operations costs through YE 2016

• Test data gathered is being evaluated

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

Panny LEAD Pilot

Bitumen – Panny Bluesky

STRATEGIC PRIORITY #4

OPTIMIZE BALANCE SHEET FOR GROWTH

24

Balance Sheet

Sufficient liquidity to fund growth-oriented capital program

Net bank debt: $11 million(1)

• Credit facility borrowing limit set at $40 million; Term extended until May 2019

• Next borrowing limit redetermination scheduled prior to November 30, 2017

Term Loan: $35 million• $45 million capacity. 8.1% interest rate; Matures March 2021

• Remaining $10 million draw required prior to November 2017

Senior Unsecured Notes: $32 million

TOU Share-based loan: $19 million• 40% loan to value ratio established at funding

• Margin triggers reset if loan to value ratio exceeds 55% (TOU share price< $20.44/share)

TOU Shares: 1.67 million @ $24.55/share: ($41 million)(1)

Total net debt less TOU share value = $ 56.5 million(1)

(1) Estimated at June 30, 2017, adjusted for July financing transactions

Series Face ValueCoupon

RateMaturity

DateSemi Annual Interest

Payment dates

8.75% 2019 $14.5 million 8.75% July 23, 2019 January 23 & July 23

8.75% 2022 $17.9 million 9.75% to Jan 2018;

8.75% thereafter

Jan 23, 2022 January 23 & July 23

25

Debt Repayment Profile

2017 financings strengthened debt repayment profile and secured funding for growth plans while enhancing liquidity

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Forecast Debt Repayment Profile 12/31/2017

TOU Loan Bank Debt Senior Notes Term Loan

13%

42%45%

26Transformational asset dispositions coupled with financing transactions materially improved balance sheet & established liquidity to execute growth strategy

Improving Balance Sheet

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Debt Total Net Debt to Adjusted Funds Flow

• Top quartile operating costs with elimination in 2016 of high fixed cost mature shallow gas assets combined with infrastructure control, and increasing production profile

• Reduced TCPL tolls through West Central Alberta concentration

• Reduced G&A with elimination of mature shallow gas assets

Reduced Costs

27

Increasing Netbacks

2018 Cash costs per boe down >25% improving netbacks

Increasing margins driven by:

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28

Diversified natural gas pricing from AECO to a basket of market indices expected toenhance 2018 funds flow by ~ $1.2 million per year

Natural Gas Market Diversification Strategy

Established pricing across diversified portfolio of end-use markets

Locked in term spreads and swapped back to Daily Index at each downstream delivery point

Physical delivery at AECO NIT; 25,000 MMBtu/d

Receive Daily Index market price for each location, less published transportation and fuel costs, plus $.02 USD/MMBtu premium

Effective Nov 1, 2017; 5 year term

Full Opportunity to manage pricing / hedge new markets

Daily Index can be swapped to Monthly Index at any individual market to manage front month pricing

Term hedges can be established to manage price at any individual market, for all or any portion of the delivery period

Multiple advantages of spread strategy vs. contracting pipe capacity

5 year exposure vs. longer term generally required for contracted pipe capacity matches expected timing for AECO supply to re-balance in broader market

No regulatory requirements or export permits required for US markets

Credit efficient structure through physical delivery obligation at AECO

Expected to enhance funds flow in 2018

Estimated to enhance PMT netbacks in 2018 by $0.12/GJ on contracted volumes ($0.05/GJ blended across total 2018 volumes)

$1.70

$1.80

$1.90

$2.00

$2.10

$2.20

$2.30

$2.40

$2.50

$2.60

$2.70Perpetual Netback Price vs AECO Strip

AECO C$/GJ Perpetual Price C$/GJ on Netback

AECO

Empress 2,000

Dawn 5,000

Mich Con3,000

Chicago 8,000

Malin 7,000

2018 Natural Gas Markets (MMBtu)

INVESTMENT THESIS

TORQUE TO GAS PRICE RECOVERY

POTENTIAL FOR MULTIPLE EXPANSION RELATIVE

TO PEER GROUP

COMPELLING DISCOUNT TO NET ASSET VALUE

30

Torque to Gas Price Recovery

• ~ $10 to 13 million increase in adjusted funds flow (incremental $0.17 to $0.22 per share)

~25% increase in 2018 funds flow (1)

~10% reduction in year end 2018 debt

Combines to drive TTM Net Debt to Funds Flow ratio below 2 times

•Potential to realize proceeds from Call Option on 33,611 GJ/d to August 2018

Q1 2018: 10,000 GJ/d > $3.50/GJ; 23,611 GJ/d > $2.81/GJ

April – August 2018: 33,611 GJ/d > $2.81/GJ

•Increased likelihood of incremental value from investment in 1.667 million TOU shares

1) Assuming continued investment in production growth, 2018 funds flow forecast at current strip $40 to $45 million ($0.67 to $0.75 per share)

$0.50/GJ in 2018 gas price

Close to 90% natural gas weighting, call option from 2016 shallow gas disposition and TOU share investment compound leverage to improving natural gas prices

31

Share Price Performance

2017 EV/Debt Adjusted Funds

Flow

2018 EV/Debt Adjusted Funds

Flow2017 EV/Boe/d

2017 YE Debt/Funds

Flow

PMT Valuation (1) 6.6X 7.0X $16,000 6.0X

Jr. ProducerPeer Group Average (1) 6.8X 7.4X $26,000 2.9X

Internal Estimate 4.5X 4.0X $17,000 3.3X

Delivering on 2017/18 business plan should drive multiple expansion

(1) Peters & Co data August 28, 2017

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10/3/2016 11/3/2016 12/3/2016 1/3/2017 2/3/2017 3/3/2017 4/3/2017 5/3/2017 6/3/2017 7/3/2017 8/3/2017 9/3/2017

Last 11 Months of Trading (Post Shallow Gas Disposition)

PMT TOU Peer Group

32

Sum of the Parts

Reserve-Based NAV, adjusted for debt, equity financing & TOU shares, is $6.36/share

Trading materially below reserve-based net asset value

(1) Year-end 2016 reserves based on McDaniel reserves and pricing, adjusted for 1.67 MM TOU shares @ $28/share and Q1 equity issuance(2) Undeveloped land replaced with risk-discounted prospect inventory; Includes appreciation of TOU shares based on 12 month TOU consensus

target price of $ 39/share(3) Unrisked prospect inventory; Includes appreciation of TOU shares based on 12 month TOU consensus target price of $ 39/share

33

Key Investment Highlights

High Quality Assets

Asset base repositioning for resource-style and diversification successful

Edson Wilrich liquids-rich gas inventory well-defined providing high capital efficiency growth

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 high netback production in asset mix

Track Record of Operational Performance

Execution and operational excellence in chosen strategies

Multiple Levers to Manage Balance Sheet

Liquidity established to fund capital program

Additional potential for growth in available liquidity through credit facility expansion, TOU share price appreciation and future warrant exercise

Pursuing further asset dispositions to continue to enhance liquidity

Value

Trading well below ‘Reserve-Based’ Net Asset Value

Enterprise value/ debt-adjusted funds flow ~50% below peer average at 4.0 times 2018 funds flow at strip pricing

Tremendous leverage to gas prices with asset mix, Shallow Gas disposition call option and TOU exposure

High impact value potential from medium to long term assets

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

34

ADDITIONAL INFORMATION

Sue Riddell Rose President & CEO

Mark Schweitzer VP Finance and CFO

Lorenzo Chiarastella Investor Relations

info@perpetualenergy.com EMAIL

800.811.5522 TOLL FREE

403.269.4400 PHONE

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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

APPENDIX

36

Transformational Transactions

Warwick Gas Storage Sale: (May 2016)

Sold remaining 30% partnership interest ($23 million)

Senior Notes Swap: (May 2016)

Retired Senior Notes via swap for 4.4 MM TOU shares ($214 million)

Shallow Gas Disposition: (Oct 2016)

Vast majority of Eastern Alberta shallow gas assets sold Oct 1/16 (nominal proceeds - Eliminated negative funds flow assets)

Reduced asset retirement obligation ($128 million)

Retained gas price upside exposure on ~90% of forecast production for 2 years

Financing Transactions: (H1 2017)

AIMCo 8.1% 4 year Term Loan & 5.4 MM warrants ($45 million)

Equity issuance 5.1 MM shares & 1.1 MM warrants ($9 million)

Senior Notes Management: (H1 2017)

Senior notes maturity extension to Jan 2022 ($17.9 million)

Early redemption of 2018 Senior Notes in April 2017 ($27.6 million)

Optimized Credit Facilities (H2 2017)

Increased reserve-based credit facility limit to $40 million capacity

Refinanced TOU share margin loan for lower cost

Positive Impact:

High graded asset base for increased netbacks

Established sustainable cost structure, including $6MM/year of reduced G&A

Strengthened balance sheet with 85% reduction in debt through $240 million repayment of senior notes and $67 million of new funding

Secured liquidity to execute growth-oriented capital program

Enhanced flexibility to manage TOU share investment

Improved debt maturity profile

Transformational transactions in 2016 & 2017 YTD position Perpetual for profitable growth and value creation

Nominal proceeds + 2 year call option

Deferred Purchase Price through 2 year call on AECO gas price > $2.81/GJ for 33,611 GJ/d

Metrics Impact

Production: (35.5 MMcfe/d)

Funds Flow: $5 - 10 MM/year

TPP Reserves: (14 MMboe)

NPV(10) TPP: $6.5 MM

Well Count: 2,952 to 495

ARO Liabilities (excl salvage): $123 MM to $35 MM

LLR: 2.1 to 3.8

Net Asset Value (PV10): $28.5 MM

37

Retained Assets West Central (including East Edson) Mannville (shallow gas & heavy oil) Panny (shallow gas & bitumen) Oil sands leases (& area P&NG) Other exploration acreage Gas over Bitumen royalty credit income stream

Disposed Assets 2,221 net wells

– 584 producing, 910 shut-in, 727 abandoned

353,777 net undeveloped acres

Accretive to Perpetual on all value metrics & 2 year gas price upside retained

Material decrease in production & reserves offset by increase in cash flow & value

Shallow Gas Disposition – October 1, 2016

38Inventory of 36 (32.3 net) locations of which 7 (6.0 net) are booked in McDaniel year end

Well Economics

Capital (D,C & T) $0.8 MM

NPV @ 10 % $1.1 MM

ROR 71%

F&D $12.32 / boe

Payout 1.5 years

Capital Efficiency(First Year)

$16,300/boe/d

Recycle Ratio(First Year)

2.8

Oil over shakers while drilling Sparky development pad HZ pad site

Assumptions

2017 Pricing(McDaniel Jan 2017 forecast)

CA$49.70/bbl wellhead heavy priceWTI US$55.00/bbl, WCS CA$53.70/bbl, Offset CA$-4.00/bbl

Operating Costs$5.90/boe (first year) &$12.70/boe (lifetime)

Average Well IP 75 bbl/d to 52 bbl/d in year 1

Ultimate Recovery 75 Mbbl per well

RoyaltiesMixed Crown (Modernized Royalty Framework) and Freehold

Mannville Heavy Oil Drilling Inventory

39

Working Interest 66.7%

OOIP: 38 MMbbl gross Cum Prod’n + McDaniel P+P: 0.9 MMbbl net (4% recovery factor)

Internal forecast: 1.1 MMbbl net (5% recovery factor)

20 Horizontals drilled to date10 inventory locations remain (5 booked in McDaniel)

1 well targeting banked waterflood oil drilled in 2017, currently producing at 90 bbl/d

Remaining locations pending additional pressure rebound from injection

Implementing Waterflood 7 injectors converted in 2013/2014

1 injection conversion remains in 2017 (booked in McDaniel)

Waterflood Response - Mannville I2I

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

6 m OIL PAY

Sparky Mid Sand

> 24 % DENSITY POROSITY

Mannville I2IWaterflood Pool

Waterflood injection optimization showing increasing oil response

Increasing reservoir pressure allowed for drilling of infill targeting banked oil

0

100

200

300

400

500

6/1/2014 6/1/2015 6/1/2016 6/1/2017 6/1/2018

Oil

rate

(b

bl/

d)

Actual Oil Rate

Primary Recovery Forecast

Internal Forecast

Internal Plus Infill Wells

McDaniel PPDP

McDaniel TPP

Actual Oil Rate Without Infill

Primary Recovery Forecast

Internal Forecast McDaniel YE 2016

40

Conventional Shallow Gas

Belly River

Viking

Grand Rapids

Lower Mannville

Pre Cretaceous Unconformity

Conventional shallow gas asset base characteristics

Primarily Mannville Area remaining post shallow gas disposition

Cretaceous sweet shallow gas <800m

Current production ~ 6.4 MMcf/d

Base declines < 10 -15%

Multiple stacked zones and play types sourcing recompletion inventory

Extensive plant & pipeline infrastructure with unutilized capacity

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

Marginal current netbacks highly leveraged to improving natural gas prices

Operational Focus

Facility optimization projects, workovers and uphole recompletions payout in months

Low cost production and reserves adds

23 recompletions/workovers/optimizations added 1.7 MMcf/d since Dec 2016

Drive fixed and variable operating cost reductions

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

Further reduce asset retirement obligation project costs

Prospecting for tight reservoirs in high resource potential traps for development with horizontal wells & multi-stage frac technology

Value optimization focuses on intense program approach to recompletion/workovers combined with abandonment and reclamation projects

301 net sections (192,416 net acres) of oil sand leases

Various formation targets and ultimate recovery methods

6 potential project areas with varying potential

Over 3 billion bbls OBIP(1) at Liege and Panny

278 Mbbl contingent resource

467 MMbbl additional prospective resource

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

Retained 1% GORR

41Bitumen lands represent large resource in place and material option value

R1W5 R21 R17 R13W4R5R9

T98

T95

Perpetual OS Leases

Overriding Royalty Lands

Perpetual Panny Pilot

Experimental

Primary Projects

Thermal Projects

(1) McDaniel 2011 estimate ~ equivalent to internal estimate

Bitumen

42Electrical 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 production in March 2016

Four cycles executed through 2016 and Q1 2017 of varying heat stimulation and solvent parameters

Exceeded cumulative oil production expectations by >100%

Second stage of pilot

Guided by first stage learnings and economic viability assessment to be scoped in 2017

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

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

LEAD Process Technology PilotLow Pressure Electro-Thermally Assisted Drive