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C O R P O R AT E P R E S E N TAT I O NS E P T E M B E R 2 0 1 9
BOLD IDEAS FOR ENERGY
1
▪ This presentation contains forward-looking information and statements relating to Perpetual's business and operations that are based onmanagement'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 areintended 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 variablecommodity cycles and anticipated value creation arising from such opportunities; Perpetual's top strategic priorities including reducing debt and restoringcash 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 arebeyond our control and are difficult to predict. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in suchforward-looking statements.
▪ The forward-looking information and statements contained in this presentation are made effective July 31, 2019. You should not placeundue reliance on these forward-looking statements, which speak only as of the date of this presentation. Unless legally required, Perpetual undertakes noobligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise.
▪ Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are:inaccuracies in the estimated timing and amount 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 costsof rented or contracted equipment, increases in labor costs, volumes of oil or gas greater or lesser than anticipated, and changes in applicable regulationsand 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 ofnatural 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 capitalmarkets and under our bank credit facility; our level of indebtedness; the ability of financial counterparties to perform or fulfill their obligations underexisting agreements; write downs of our asset carrying values and oil and gas property impairment; the discovery of previously unknown environmentalissues; changes in our business and financial strategy; inaccuracies in estimating the amount, nature and timing of capital expenditures, including futurefinding and development costs; the inability to predict the availability and terms of capital; issues with marketing of natural gas and oil including lack ofaccess of markets, changes in pipeline and transportation tariffs and costs, increases in minimum sales quality standards for oil or natural gas, changes inthe 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 newdiscoveries 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, includingblow-outs, surface caterings, fires, explosions; the competitiveness of alternate energy sources or product substitutes; technological developments; changesin governmental regulation of the natural gas and oil industry potentially leading to increased costs and limited development opportunities; changes ingovernmental regulation of derivatives; developments in natural gas-producing and oil-producing countries potentially having significant effects on the priceof gas and oil; the effects of changed accounting rules under generally accepted accounting principles and IFRS; the amount of future abandonment andreclamation costs, asset retirement and environmental obligations; inability to execute strategic plans and realize projected economics, expectations andobjectives for future operations and price risk management strategies; and the other risk factors identified in our most recent financial statementsand management's discussion and analysis and Annual Informational Form and our other filings on SEDAR. Unpredictable or unknown factorsnot 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
Financial Profile (TSX: “PMT”)June 30, 2019 except as noted
Common Shares o/s (1) 60.3 million
Management & Insider ownership 49%
Share price (1) $ 0.18
Market capitalization $ 11 million
Net bank debt (2)(4) $ 48 million
TOU share-based loan (3) $ 14 million
Term loan $ 45 million
Senior unsecured notes $ 34 million
Tourmaline Oil Corp. Shares (1.66 million) (3) ($ 21 million)
Net debt (4) $ 120 million
Enterprise value (4) $ 131 million
(1) September 4, 2019 closing market price and common shares outstanding(2) Revolving bank debt, net of net working capital deficiency (4) at June 30, 2019(3) Loan secured by 1.66 MM Tourmaline Oil Corp. (TSX:”TOU”) shares; Closing market price at September 4, 2019 $12.88/share(4) See Non-GAAP measures advisory in this presentation
4
• Mannville heavy oil
• Heavy oil exploration
• Conventional shallow gas
• Viking shallow shale gas
• Bitumen
Eastern Alberta
• Edson Wilrich
• Multi-zone liquids-rich gas
• Tight oil & gas exploration
West Central
Asset Summary
Production (1) (79% West Central/21% Eastern Alberta) 9,370 boe/d
Natural Gas (79%) 7,409 boe/d
Oil and NGL (21%) 1,961 bbl/d
P+P Reserves (2) 67.9 MMboe
Reserve to Production Ratio (P+P) (RLI) (3) 20 Years
Bitumen (DPIIP) (4) 1,292 MMbbl
Tourmaline Oil Corp. Shares – 1.66 million (5) $ 21 million
Operating Profile
(1) Q2 2019 production (2) Year End 2018 N1 51-101 McDaniel Report on Reserves Data(3) Year End 2018 Reserves divided by year one production estimate from 2018 McDaniel Report (4) DPIIP (Discovered Petroleum Initially In Place), evaluated by internal qualified reserves evaluator in accordance
with COGE Handbook effective January 1, 2019(5) Closing market price @ September 4, 2019 = $12.88/TOU share
5
Q4 2016 to Q3 2019Executing A Transformation
High Grading the Asset Base
• Shallow Gas Disposition October 1, 2016
• Sold non-core assets in 2018 for $13 million
• Captured new opportunities aligned with strengths and chosen strategies
Improving the Balance Sheet
• Increased revolving bank line to $55 million and extended term to November 2020
• Arranged AIMCO $50 million second lien term loan and equity placement
• Established $14 million self-funded TOU share based loan
• Actively managed senior note maturities
▪ Early redeemed 2018 senior notes
▪ Refinanced 2019 Senior Notes through exchange for 2022 Senior Notes
Diversifying the Revenue Base
• Secured 5 year market diversification contract to shift gas price exposure on 40,000 MMBtu/d from AECO to basket of five North American price hubs
• Contract term extended by two years to October 31, 2024
▪ Nov 1/17 – June 30/19 = $25.5 million incremental revenue over AECO sales
▪ July/19 - Oct/24 mark to market = $11.3 million
• Focused capital investment to increase oil & NGL to >20% of production mix
Investing for Value with Operational Excellence• Drilled 18 wells at East Edson & increased plant capacity to 78 MMcf/d
▪ East Edson production up 15% (Q4 2016 to Q2 2019)
▪ Peak production in Q1 2018 - Now declining with deferred investment to optimize value
• Drilled 13 heavy oil wells & waterflood investment at Mannville
▪ Grew Mannville heavy oil production 30% (Q4 2016 to Q2 2019)
• Progressive ARO management utilizing area-based closure
• Embracing innovation & technology to produce an ever-cleaner molecule
Positive Impact
• Focused core assets
• Well-defined drilling inventory
• Diversified revenues
• Increased netbacks
• Improved liquidity and debt maturity profile
• Enhanced flexibility to manage TOU share investment
Positioning for value creation and managing risk
6
(1) Guidance released July 31, 2019
(2) See Non-GAAP measures advisory in this presentation
Capital Spending
($ millions)2017 2018 Q1-Q2 2019 Q3-Q4 2019
Guidance (1)
2019Guidance (1)
West Central
Liquids-Rich Gas
$6514 gross
(13.4 net) drills
$141 gross
(1.0 net) drill
(3 frac’s)
$1.1
Facilities
$9 - $10
Up to 2 gross
(2.0 net) drill & frac
$10 - $11Up to 2 gross
(2.0 net) drill & frac
Eastern
Heavy Oil
$85 gross
(4.3 net) drills
$136 gross (6.0 net)
drills
1 re-entry
$5.3
3 gross
(3.0 net) drills
1 re-entry
$3 - $5
Up to 2 gross
(2.0 net) drills
$8 - $10Up to 5 gross
(5 net) drills
1 re-entry
Total (1)
$73 $27 $6.4 $12 - $15 $18 - $21
• 2018 proved and probable reserve additions replaced 134% of 2018 production at attractive F&D cost of $5.09/boe (FD&A - $2.43/boe)
• 2018 & 2019 Capital Spending funded by adjusted funds flow (2)
• Additional anticipated Asset Retirement spending of $1.5 to $2.0 million in 2019▪ 2018 - $2.0 million; 2017 - $2.3 million
Drilling location inventory supports reallocation of 2019 capital to either operating area as commodity prices dictate
10,594
8,118
9,876 10,2409,370
8,636
9,193
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
Q4 2016 2017 Q1 2018 Q2 2018 Q3 2018 Q4 2018 Q1 2019 Q2 2019 Q3 2019E Q4 2019E
Ave
rage
Dai
ly P
rod
uct
ion
(B
oe
/d)
Gas Production NGL Oil 2018 2019 Guidance
2019 Guidance(1) = 9,200 - 9,500 Boe/d
7
Capital plan in 2019 balanced between oil and gas but flexible to adjust based on commodity prices
Production Optimized for Value• ~15% forecast production growth (Q4 2019 vs. Q4 2016)
• Forecast production mix shift to ~25% oil & NGL by Q4 2019
Ongoing Strategies
• Summer shut-ins driven by extreme low AECO gas prices to preserve reserves
• Capital profile to peak natural gas production during winter months to maximize capture of highest gas prices
• Investment skew for growth in higher return Mannville heavy oil projects
Production
(1) 2019 Guidance released July 31, 2019
Post Shallow Gas Disposition
0.00
2.50
5.00
7.50
10.00
12.50
15.00
17.50
20.00
22.50
25.00
27.50
Q4 2016 2017 Q1 2018 Q2 2018 Q3 2018 Q4 2018 Q1 2019 Q2 2019 Q3 2019E Q4 2019E
$/Bo
e
Operating Costs Transportation Costs Royalties Cash G&A Interest RevenuePost Shallow Gas
Disposition
• Top quartile operating costs with East Edson concentration combined with infrastructure control, operatorship and low cost culture – largely fixed operating cost base
• Reduced TCPL tolls through West Central Alberta production concentration and optimization
• Royalties driven off AECO pricing while netbacks include market diversification contract uplift
Reducing Costs
• Market diversification contract to minimize AECO exposure and shift exposure to higher priced markets
• Capital timed to peak gas production during winter months and allows declines through Q2/Q3
• Focus capital to higher netback heavy oil projects
Maximizing Revenue
8
Operating Netback
Optimizing netback in lower commodity price environment by:
Maximizing operating netbacks through revenue and cost strategies
(1) See Non-GAAP measures advisory in this presentation(2) 2019 Forecast reflects average guidance released July 31, 2019
Operating Netback (1)(2)
• Q2 2019 = $10.69/Boe
AECO fixed price, 9%
Empress, 7%
Dawn, 14%
Michcon, 9%
Chicago, 21%
Malin, 19%
Natural gas liquids -Condensate, 3%
Natural gas liquids -Other, 2%
Crude Oil - Fixed, 5%
Crude Oil, 11%
2019 Price Exposure Net of RoyaltiesNatural gas market shift to diversify portfolio• 40,000 MMBtu/d; 5 year term Nov/17 - Oct 31/22
• Receive Daily Index market price at five downstream delivery points less published transportation and fuel costs plus $0.02 USD/MMBtu premium
• Contract extended by two years to October 31, 2024
Full opportunity to manage pricing• 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
Advantages vs 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
Enhanced adjusted funds flow (2)(3)
• 2018: Incremental revenue of $19.5 million ($1.02/Mcf incremental over AECO Daily Index price averaged across total PMT natural gas sales)
• 2019E: Forecast incremental revenue of $11.2 million ($0.70/Mcf incremental over AECO Daily Index price averaged across total PMT natural gas sales)
• H1 2019 contributed $6.9 million toward realized natural gas price of $2.93/Mcf (60% uplift over AECO Daily Index)
9
Market Diversification Strategy
Gas market diversification contract forecast to provide significant premium prices over AECO with increased pricing stability
(1)
(1) As per Guidance released July 31, 2019(2) Settled incremental contract revenue since
inception to June 30, 2019 = $25.5 million(3) Open Mark to Market incremental contract
revenue July 2019 to Oct 2024 = $11.3 million
10
2019 Adjusted Funds Flow Guidance
2019 adjusted funds flow guidance: $0.30 - $0.34 per share
(1) Cash flows from operating activity sensitivities are comparable to adjusted funds flow sensitivities; See Non-GAAP measures advisory in this presentation
(2) See July 31, 2019 MD&A and News Release “Outlook” for additional guidance and assumptions
(3) 2019 forward average prices assume MD&A: NYMEX gas price = US$2.68/MMBtu; WTI price = US$58.67/bbl; WCS differential = US$14.18/bbl; CAD/USD Exchange Rate US$1.00 = $1.32
2018 2019 Guidance (2)
Exploration and development expenditures $26.5 million $18 - $21 million
Cash costs (1) $15.06/boe $17.00 - $18.00/boe
Average daily production 10,594 boe/d 9,200 - 9,500 boe/d
Average production mix 17% oil & NGL 20% - 24% oil & NGL
Adjusted Funds Flow (3) $30.2 million $18 - $21 million
• H1 2019 Net cash flows from operating activities - $13.6 million ($0.23/share)
• H1 2019 Adjusted funds flow - $10.0 million ($0.17/share)
$0.0 $1.0 $2.0 $3.0 $4.0 $5.0 $6.0
Cdn$/US$ Exchange Rate (+/- $0.05)
Oil & NGL Production (+/- 100 Bbl/d)
Gas Production (+/- 2.5 MMcf/d)
WTI Oil Price (+/- USD $2.50/bbl)
NYMEX gas price (+/- $0.25 USD/MMBtu)
($ millions)
2019 Adjusted Funds Flow Sensitivities(1)(3)
11Positioning for short and long term value creation
Improve Balance Sheet and Manage Risk
Grow Value of Greater Edson Liquids-Rich Gas
Grow Value of Eastern Alberta Portfolio
Advance High Impact, Diversifying New Ventures
2019 Strategic Priorities
STRATEGIC PRIORITY #1IMPROVE BALANCE SHEET AND MANAGE RISK
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2019 Financing Initiatives
Available liquidity (1)(2) of ~$20.5 million
• Comprised of available bank line plus TOU share investment, net of TOU share-based loan
• Planned capital program fully funded by 2019 adjusted funds flow (3)
Credit facility extended 1.5 years to November 30, 2020
• $55 million borrowing limit
• Redwater Supreme Court decision fully considered through renewal process
• Next semi-annual borrowing base redetermination scheduled for November 2019
2019 Senior Notes early redemption
• $14.6 million Senior Notes due July 23, 2019 redeemed June 11, 2019
▪ Fully backstopped exchange for additional issuance of $15.7 million 2022 Senior Notes
Refinancing 2019 Senior Notes further improves Perpetual’s debt repayment profile
(1) Bank Debt at June 30, 2019, adjusted for market price of TOU share investment at September 4, 2019
(2) See Non-GAAP measures advisory in this presentation
(3) As per Guidance released July 31, 2019
14
Balance Sheet
Balance Sheet (1) Security MaturityAmount
($ millions)
Tourmaline Shares (1)
• 1.66 million shares @ $12.88/share N/A N/A $(21.3)
Tourmaline Share Demand Loan
• 55% loan to value margin trigger TOU Shares Demand $14.1
Net working capital deficiency (3) N/A N/A $10.3
Revolving Bank Debt
• $55 MM borrowing limit
• $3.7 MM letters of credit outstanding 1st Lien November 30, 2020 $37.8
Term Loan (8.1%) 2nd Lien March 14, 2021 $45.0
2022 Senior Notes (8.75%) Unsecured January 23, 2022 $33.6
Net Debt (1)(3) $119.5
Net debt to adjusted funds flow (3)(4)
• As at December 31, 2018
• As at December 31, 2019 (2)
3.7 times
6.1 times
(1) As at June 30, 2019, adjusted for market price of TOU share investment September 4, 2019
(2) As per mid-point Guidance released July 31, 2019
(3) See Non-GAAP measures advisory in this presentation
(4) Trailing 12 month (“TTM”) adjusted funds flow
Over 65% of net debt is long term
15
Sequoia Litigation
Positive decision on Summary Dismissal Application received on majority of issues. Appeal process expected to result in full dismissal of claim in 2020.
Date Action (1)
October 1, 2016 • Perpetual closed the Shallow Gas Disposition to an arm’s length third-party previously unknown to Perpetual (Sequoia) at negotiated fair market value after an extensive and lengthy marketing, due diligence and negotiation process
March 23, 2018 • Sequoia assigned itself into bankruptcy
August 3, 2018 • PwC initiates litigation against Perpetual and schedules August 30, 2018 court date
August 27, 2018 • Perpetual files statement of defence and application for summary dismissal based on determination of threshold issues:Allegations: August 15, 2019 Judgement:➢ Were parties dealing at arm’s length? Test for dismissal application not met – trial required➢ Is PwC entitled to bring an oppression claim? No➢ Is there a public policy claim to pursue? No➢ Should the director duties claim continue? No
August 26, 2019 • Perpetual and PwC both filed appeals against their respective elements of August 15, 2019 judgement
Q1 2020 • Appeal hearing expected to be conducted
Q2 2020 • Appeal judgment expected to be received (1) Court documents available at www.perpetualenergyinc.com
Application for Summary Dismissal on Threshold Issues
Summary Dismissal Court Decision receivedWritten Decision still pending
Final Outcome
Favourable UnfavourableAppeals filed
Q4 2018
August 15, 2019
Q1 – Q2 2020
2021 – 2026
Full litigation of arm’s length issue and possibly other PWC claims (1 – 5 years)
STRATEGIC PRIORITY #2
GROW VALUE OF GREATER EDSON
LIQUIDS-RICH GAS
1766 (63.3 net) locations booked in 2018 Year End McDaniel reserve report
4 ERH locations ready to execute with 2 planned for Q4 2019
Edson Activity
ERH pads• 2,500 – 3,500 meters
Area Capacity: 78 MMcf/d• West Wolf: 65 MMcf/d• Rosevear: 13 MMcf/d
Pre 2017 Drills2017 Drills2018 Drills2019 Drill Ready
2014: East Edson JV Royalty deal
•Sold 5.6 MMcf/d plus associated liquids for $120 MM investment
2015: Growth driven by JV Royalty sale commitments
•Constructed new 30 MMcf/d West Wolf Lake plant on stream July 2015 & expanded to 45 MMcf/d September 2015
•Drilled to fill East Edson facilities and transportation contracts
▪ 60 MMcf/d plus NGL’s: 45 MMcf/d at West Wolf & 15 MMcf/d WI owner capacity at Rosevear
2016: Preserving value in low gas price environment
•1 drill only and allowed for natural declines
•Shut-in sour volumes through third-party facility
2017: Drill to grow production to expanded TCPL transportand plant capacity
•1 rig Wilrich drilling program to fill existing infrastructure & meet new transport in December 2017 (originally scheduled for April 2018)
•Added 15 MMcf/d compression West Wolf for area capacity of 78 MMcf/d
2018: Optimize value through seasonal production
•Allow summer declines and ramp up production for stronger winter pricing
2019: Sustain with Wilrich and Secondary Zone Evaluation
•No capital spend until stronger AECO prices evident (potentially Q4 2019)
•Advance evaluation of secondary Viking, Notikewin, Fahler & Gething horizontal development potential supported by 3D seismic
18Infrastructure 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)
Greater Edson Liquids-Rich Gas Wilrich Play Performance
0
5,000
10,000
15,000
20,000
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
2011
2012
2013
2014
2015
2016
2017
2018
2019
E
Cu
mu
lati
ve P
rod
uct
ion
(M
bo
e)
Bo
e/d
19
Edson Type Curves
Year End 2018 reserves reflect strong base well performance
McDaniel YE 2018 TPP West Type Curve Economics (1)
Price Deck 3 Consultant Average Jan 1/2019
Capital (D,C & T) $ 4.5 MM
NPV @ 10 % $ 2.8 MM
ROR 34%
F&D $ 6.35/ boe
Capital Efficiency $7,700 boe/d
Payout 2.6 Years
Recycle Ratio 1.8
Year 1 Pricing $1.78/ GJ (AECO); $49.48/bbl NGL
Operating Costs $1.70/ boe (first year)
Well Depth 4,350 M HZ; 2,625 TVD
Lateral Length 1,700 Meters
Type CurveIP 7.0 MMcf/d1 year exit rate 1.8 MMcf/d16.1 bbl/MMcf NGL/condensate
2P Reserves 4.2 Bcfe per well
⚫Well defined TPP type curves(1) provide reliable forecasts ⚫ERH wells length-adjusted to increase rate & reserves per well⚫Three Consultant Average prices provides compelling investment thesis⚫Current natural gas strip prices suggest deferring capital investment increases value
Average(2)
West TPP Type Curve(3)
West TPP Low Type Curve(3)
East TPP Type Curve(3)
(1) Actuals and type curves adjusted to common 1,800m length by linearly adjusting completed length; Rate*1,800/(completed horizontal length (m)). All rates are raw gas and exclude associated liquids
(2) Averages represent normalized moving average rate of all Perpetual wells rig released since Jan 2014(3) East Edson East and West type curves derived from 2018 N1 51-101 McDaniel Proved Plus Probable (TPP Report) on reserves data (the “N1 51-101 Report”)
+
Continuous improvement in drilling & frac design driving strong capital efficiency & reduced future development capital
• 2017/18
◼ Monobore design proved up for 1,700 metre type curve length wells
◼ Extended reach horizontal wells (“ERH”) targeting 2,200 to 3,400 metre lateral lengths
◼ Dissolvable frac balls, eliminating costs to drill out balls and seats
• 2019
◼ Optimized monobore design for 2,500 meter lateral and modified frac design
20
(1) Capital efficiency = Cost to drill, complete, equip and tie in/first 12 months average daily production, based on actual capital and average daily production to date (with McDaniel 2018 PDP forecast for wells onstream less than 12 months). The ERH estimate is based on future estimates of proven undeveloped locations from the McDaniel 2018 report.
East Edson Wilrich Capital Efficiency
Targeting further improvements in capital efficiency
21Higher production over fixed cost base drives top quartile operating cost structure
Top Quartile Operating Cost Structure
(1) See July 31, 2019 news release “Outlook” for Operating Cost guidance assumptions
0.00
3.00
6.00
9.00
12.00
0
500
1,000
1,500
2,000
Ma
y-1
4
Jun
-14
Jul-
14
Au
g-1
4
Sep
-14
Oct
-14
No
v-1
4
De
c-1
4
Jan
-15
Feb
-15
Ma
r-1
5
Ap
r-1
5
Ma
y-1
5
Jun
-15
Jul-
15
Au
g-1
5
Sep
-15
Oct
-15
No
v-1
5
De
c-1
5
Jan
-16
Feb
-16
Ma
r-1
6
Ap
r-1
6
Ma
y-1
6
Jun
-16
Jul-
16
Au
g-1
6
Sep
-16
Oct
-16
No
v-1
6
De
c-1
6
Jan
-17
Feb
-17
Ma
r-1
7
Ap
r-1
7
Ma
y-1
7
Jun
-17
Jul-
17
Au
g-1
7
Sep
-17
Oct
-17
No
v-1
7
De
c-1
7
Jan
-18
Feb
-18
Ma
r-1
8
Ap
r-1
8
Ma
y-1
8
Jun
-18
Jul-
18
Au
g-1
8
Sep
-18
Oct
-18
No
v-1
8
De
c-1
8
Q1
-19
Q2
-19
Q3
E-1
9
Q4
E-1
9
Op
era
tin
g C
ost
s/B
oe
($
/Bo
e)
Mo
nth
ly O
pe
rati
ng
Co
sts
($0
00
's)
East Edson Operating Costs
Operating Costs Operating Costs ($/Boe)
STRATEGIC PRIORITY #3
GROW VALUE OF EASTEN ALBERTA PORTFOLIO
23
Eastern Alberta – Mannville Heavy Oil
2019 Capital program targets development drilling, exploration targets and waterflood optimization projects
(1) Parameters as per 2018 NI 51-101 McDaniel Report in accordance with COGE Handbook effective Jan 1, 2019. Recovery factor based on aggregate McDaniel total proved plus probable reserves
(“TPP “)+ Cum produced to date divided by aggregate DPIIP. Initial rates as per range in PPUD bookings.
Mannville Q2 2019 Production
•Area production of 1,938 boe/d (62% oil)
• 6 oil pools producing 1,194 bbl/d
▪ Increase of 30% from Q4 2016
• Power Generation of ~800 kW/d improves natural gas production netbacks
Access to Large Oil Resource
•> 190 MMbbl Discovered Petroleum Initially In Place(1)
• 4.7 MMbbl produced to date (<3%)
• 4.3 MMbbl remaining TPP reserves (4% recovery factor)(1)
Low cost HZ development
• $0.9 MM DC&T per single lateral well(1)
•Average initial rate ~50-120 bbl/d(1)
▪ 2 exploratory multi-laterals (6 laterals) drilled in Q3 to de-risk and convert unbooked heavy oil inventory to reserves
▪ 30+ follow up locations if successful
2018 drills 2019 drills2019 drill readyProducing poolsExploration pools
2018 Capital Program▪ 6 (6 net) development wells▪ 1 re-entry adding 3 laterals to an existing well2019 Capital Program▪ 5 (5 net) wells, including multi-laterals and up to 2 exploratory▪ 1 re-entry adding 2 laterals to an existing well
2416 (16.0 net) locations booked in McDaniel Year End 2018 Reserve Report
Unbooked heavy oil drilling inventory of 65 (65.0 net) locations
Well Economics
Capital (D,C & T) $0.8 - $1.1 MM
NPV @ 10 % $0.8 - $1.9 MM
ROR 40% - 165%
F&D $6.60 - $8.35 / boe
Payout 0.7 – 2.5 years
Capital Efficiency(First Year)
$15,500 - $26,100/boe/d
Recycle Ratio(First Year)
2.9 – 6.3
Oil over shakers while drilling Multi-well Pad SiteMannville Multi-well Battery
Assumptions (1)
2019 Pricing(3 Consultant Average Jan 1 2019)
CAD$44.30/bbl wellhead heavy priceWTI US$58.80/bbl; WCS CAD$51.55/bbl; Offset CAD$7.25/bbl
Operating Costs $5.75 - $7.05/boe (first year)
Average Well IP 30 - 120 bbl/d (43 – 73 bbl/d first year avg)
Ultimate Recovery 65 – 120 Mbbl oil per well
RoyaltiesMixed Crown (Modernized Royalty Framework) and Freehold
Mannville Heavy Oil Drilling Inventory
(1) Mannville Heavy Oil P+PUD (Total Proved Plus Probable) reserve parameters as per 2018 N1 51-101 McDaniel Report on Reserves Data
25
Mannville Heavy Oil Pools Waterflood Response
Waterflood response continues to support positive technical reserve revisions
(1) Upper Mannville B Pool DPIIP (Discovered Petroleum Initially In Place) and TPP Reserves, as per 2018 NI 51-101 McDaniel in accordance with COGE Handbook effective Jan 1, 2019
DPIIP (1)
(MMbbl)
Cumulativeproduction to YE 2018
(MMbbl)
TPP Reserves booked at YE 2018 (1)
(MMbbl)
Implied Recovery
Factor(%)
133 3.4 2.3 4%
Upper Mannville B Pool consists of 3 geological units, all under waterflood
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1/1/2013 1/1/2015 1/1/2017 1/1/2019 1/1/2021 1/1/2023 1/1/2025
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Rat
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Upper Mannville B Pool - Regional Lloyd Mid
Oil Rate Oil Base Forecast McDaniel PPDP 2018
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McDaniel PPDP
YE 2018
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1/1/2013 1/1/2015 1/1/2017 1/1/2019 1/1/2021 1/1/2023 1/1/2025
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Upper Mannville B Pool - Regional Lloyd Lower
Oil Rate Base Decline McDaniel PPDP 2018
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McDaniel PPDP
YE 2018
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1/1/2011 1/1/2013 1/1/2015 1/1/2017 1/1/2019 1/1/2021 1/1/2023 1/1/2025
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Upper Mannville B Pool - Lloyd Lower Channel
Oil Rate McDaniel PPDP 2018
Wat
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McDaniel PPDP
YE 2018
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1/1/2013 1/1/2015 1/1/2017 1/1/2019 1/1/2021 1/1/2023 1/1/2025
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Rat
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l/d
Upper Mannville I2I Pool
Oil Rate Oil Base Decline McDaniel PPDP 2018
McDaniel PPDP
YE 2018
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100
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1/1/2013 1/1/2015 1/1/2017 1/1/2019 1/1/2021 1/1/2023 1/1/2025
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Upper Mannville T8T Pool
Oil Rate MD 2018 PPDP
McDaniel PPDP
YE 2018
26Waterflood response materially flattened base declines in all pools
Wat
erf
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d c
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nce
d
Pool DPIIP (1)
(MMbbl)
Cumulativeproduction to
YE 2018(MMbbl)
TPP Reserves booked at YE
2018 (1)
(MMbbl)
Implied Recovery Factor(%)
Sparky I2I 38 0.8 0.8 4%
Upper Mannville T8T 11 0.2 0.4 5%
(1) DPIIP (Discovered Petroleum Initially In Place) and TPP Reserves, as per 2018 NI 51-101 McDaniel in accordance with COGE Handbook effective January 1, 2019W
ate
rflo
od
co
mm
en
ced
Mannville Heavy Oil Pools Waterflood Response
STRATEGIC PRIORITY #4
ADVANCE HIGH IMPACT, DIVERSIFYING
NEW VENTURES
⚫255 net sections (163,000 net acres) of oil sand leases
⚫Various formation targets and ultimate recovery methods
⚫6 potential project areas with varying potential
⚫Over 1.3 billion bbls DPIIP (1) at Liege and Panny
⚫Sold 37 net sections of select oil sands leases for $6.1 million in Q1 2016
◼Retained 1% GORR – Sold GORR for $10 million in Q2 2018
28Bitumen 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
Oil Sands Leases
(1) DPIIP (Discovered Petroleum Initially In Place), evaluated by internal qualified reserves evaluator in accordance with COGE Handbook effective January 1, 2019
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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 DPIIP (1)
• Reservoir simulation model supports >50% recovery factor
• Resource sufficient 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 operating costs through YE 2016
Pilot Phase 2
• Phase 2 currently 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
(1) DPIIP (Discovered Petroleum Initially In Place), evaluated by internal qualified reserves evaluator in accordance with COGE Handbook effective January 1, 2019
30Conductive heating with water or solvent injection for mobility and pressure support
⚫ First stage of pilot – single well Cyclic Heat Stimulation complete
◼ 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
◼ Four cycles executed through 2016 and Q2 2017 of varying heat stimulation and solvent parameters
◼ Exceeded cumulative oil production expectations by >100%
⚫ Second stage of pilot
◼ Second stage pilot design guided by first stage learnings and economic viability assessment to be scoped in 2019
◼ Solvent screening study underway; Alternative heat delivery systems being evaluated; Considering alternative site
◼ Decision pending to proceed with second stage of pilot as early as 2020
⚫ Pilot results will drive assessment of full scale development potential
Top Gas
Heaters / Injectors
Oil
Producer
LEAD Pilot Stage 2 Configuration
LEAD Technology Pilot Low Pressure Electro-Thermally Assisted Drive
INVESTMENT THESIS
COMPELLING DISCOUNT TO NET ASSET VALUE
TORQUE TO GAS PRICE RECOVERY
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Sum of the Parts Net Asset ValueYear End 2018
Year End 2018 Reserve-Based NAV = $4.59/share
(1) Net asset value (“NAV”) per share based on 60.2 million shares outstanding. Reserve valuation based on NPV10% McDaniel reserves and Three Consultant Average price forecast as at year end 2018; Independent third party undeveloped land assessment and financial information as at December 31, 2018.
(2) As per (1) above; Undeveloped land replaced with risk-discounted unbooked inventory; Includes incremental TOU share value based on share price as at April 10, 2019 of $21.14/share.
(3) As per (1) and (2) above; Undeveloped land replaced with unrisked unbooked inventory; See oil and gas advisories in this presentation
⚫ PPDP reserve additions replaced annual production by 134% in 2018▪ Strong base asset performance with technical revisions in East Edson and Eastern Alberta core operating areas
▪ 2018 Proved plus probable FD&A of $2.43/boe and 5.7 times recycle ratio (1)(2)
⚫ 2019 capital program includes 2 wells to de-risk and convert unbooked heavy oil inventory
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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 platform
◼ Mannville heavy oil delivering diversified cash flow with material secondary recovery potential
◼ Prospects for short and long term growth from heavy oil and natural gas focused resource-style plays
Track Record of Operational Performance
⚫ Execution and operational excellence in chosen strategies
◼ Capital programs fully funded by adjusted funds flow
Manageable Balance Sheet
⚫ 2/3’s of net debt repayable in 2021 or later
⚫ Liquidity available through TOU share investment
⚫ Deemed assets to deemed liabilities as per AER Licensee Liability Rating is 4.5
Significant Value Potential
⚫ Attractive share price
◼ Trading significantly below Reserve-based net asset value
◼ Sequoia litigation - Positive court decision received. Appeal process expected to result in full dismissal of claims in 2020.
⚫ Tremendous leverage to natural gas prices with gas-weighted asset mix and TOU share exposure
◼ Market diversification contract provides premium NYMEX-based pricing
⚫ High impact value potential from medium to long term assets
Spectrum of opportunities for value creation
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ADDITIONAL INFORMATION
Susan Riddell Rose President & CEO
Mark Schweitzer Vice President, Finance and CFO
[email protected] 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
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Non GAAP Measure Advisories
NON-GAAP MEASURES: The terms “adjusted funds flow”, “adjusted funds flow per share”, “adjusted funds flow per boe”, “available liquidity”, “cash costs”, “gas over bitumen revenue, net ofpayments”, “net working capital deficiency (surplus)”, “net debt and net bank debt”, “operating netback”, “realized revenue” and “enterprise value” used in this corporate presentation are notrecognized under GAAP. Management believes that in addition to net income (loss) and net cash flows from (used in) operating activities as defined by GAAP, these terms are useful supplementalmeasures to evaluate performance. Users are cautioned however that these measures should not be construed as an alternative to net income (loss) or net cash flows from (used in) operatingactivities determined in accordance with GAAP as an indication of Perpetual’s performance and may not be comparable with the calculation of similar measurements by other entities. Additionalinformation on these Non-GAAP measures, including reconciliations to applicable GAAP measures, are included in the Company’s most recently filed Management Discussion and Analysis and maybe accessed through the SEDAR website (www.sedar.com) or Perpetual’s website (www.perpetualenergyinc.com).
▪ Adjusted funds flow: Management uses adjusted funds flow and adjusted funds flow per boe as key measures to assess the ability of the Company to generate the funds necessary tofinance capital expenditures, expenditures on decommissioning obligations and meet its financial obligations. Adjusted funds flow is calculated based on cash flows from (used in) operatingactivities, excluding changes in non-cash working capital and expenditures on decommissioning obligations since Perpetual believes the timing of collection, payment or incurrence of theseitems is variable. Expenditures on decommissioning obligations may vary from period to period depending on capital programs and the maturity of the Company’s operating areas. Expenditureson decommissioning obligations are managed through the capital budgeting process which considers available adjusted funds flow. The Company has also deducted the change in gas overbitumen royalty financing from adjusted funds flow, in order to present these payments net of gas over bitumen royalty credits. These payments are indexed to gas over bitumen royalty creditsand are recorded as a reduction to the Corporation’s gas over bitumen royalty financing obligation in accordance with IFRS. Additionally, the Company has excluded payments of restructuringcosts associated with the disposition of the shallow gas assets on October 1, 2016 (the “Shallow Gas Disposition”), which management considers to not be related to cash flow from operatingactivities. Restructuring costs include employee downsizing costs and surplus office lease obligations. Commencing in the first quarter of 2018, the Company no longer excludes ‘exploration andevaluation – geological and geophysical costs’ from the calculation of adjusted funds flow as these costs are no longer significant to the Company’s business. The calculation of adjusted fundsflow for comparative periods has been adjusted to give effect to this change. Adjusted funds flow per share is calculated using the same weighted average number of shares outstanding usedin calculating income (loss) per share. Adjusted funds flow is not intended to represent net cash flows from (used in) operating activities calculated in accordance with IFRS.
▪ Available liquidity: Available Liquidity is defined as Perpetual’s Credit Facility Borrowing Limit, plus Tourmaline Oil Corp. (“TOU”) share investment, less borrowings and letters of credit issuedunder the Credit Facility and TOU share margin loan. Management uses available liquidity to assess the ability of the Company to finance capital expenditures, expenditures on decommissioningobligations and meet financial obligations.
▪ Cash costs: Management believes that cash costs assist management and investors in assessing Perpetual’s efficiency and overall cost structure. Cash costs are comprised of royalties,production and operating, transportation, general and administrative and cash interest expense and income. Cash costs per boe is calculated by dividing cash costs by total production sold inthe period.
▪ Net debt, net bank debt and net debt to adjusted funds flow ratio: Net bank debt is measured as current and long-term revolving bank debt including net working capital deficiency(surplus). Net debt includes the carrying value of net bank debt, the principal amount of the term loan, the principal amount of the TOU share margin loan and the principal amount of seniornotes, reduced for the mark-to-market value of the TOU share investment. Net debt, net bank debt and net debt to adjusted funds flow ratios are used by management to analyze borrowingcapacity. Net debt to adjusted funds flow ratios are calculated on a trailing 12 month basis.
▪ Net working capital deficiency (surplus): Net working capital deficiency (surplus) includes total current assets and current liabilities excluding short-term derivative assets and liabilitiesrelated to the Corporation’s risk management activities, current portion of gas over bitumen royalty financing, TOU share investment, TOU share margin loan, revolving bank debt, and currentportion of provisions.
▪ Operating netback: Perpetual considers operating netback to be an important performance measure as it demonstrates its profitability relative to current commodity prices. Operating netbackis calculated by deducting royalties, operating costs, and transportation from realized revenue. Operating netback is also calculated on a per boe basis using production sold for the period.Operating netback on a per boe basis can vary significantly for each of the Company’s operating areas.
▪ Realized revenue: Realized revenue is the sum of realized natural gas revenue, realized oil revenue and realized NGL revenue which includes realized gains (losses) on financial natural gas,crude oil and foreign exchange contracts but excludes any realized gains (losses) resulting from contracts related to the disposition of shallow gas properties. Realized revenue, including foreignexchange contracts, is used by management to calculate the Corporation’s net realized commodity prices, taking into account monthly settlements on financial crude oil and natural gas forwardsales, collars, basis differentials, and forward foreign exchange sales. These contracts are put in place to protect Perpetual’s adjusted funds flow from potential volatility in commodity prices andforeign exchange rates, and as such, any related realized gains or losses are considered part of the Corporation’s realized price.
▪ Enterprise value: Enterprise value is equal to net debt plus the market value of issued equity and is used by management to analyze leverage. Enterprise value is not intended to representthe total funds from equity and debt received by the Corporation upon issuance.
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Oil and Gas Advisories
OIL AND GAS ADVISORIES: The presentation refers to F&D (finding and development costs), FD&A (finding, development and acquisition costs), ROR (rate of return), payout and recycle ratiowhich have been prepared by management and are used to measure performance. These terms do not have standardized meanings or standard calculations and are not comparable to similarmeasures used by other entities. In this presentation, internal rate of return refers to the discount rate that makes the net present value of all cash flows of a project equal zero and payout refersto the time required to pay back the capital expenditures (on a before tax basis) of a project. The presentation also refers to capital efficiency which is defined as a type of capital efficiency thatmeasures the cost to add an incremental barrel of flowing production. Specifically, for the average production efficiencies of our plays, Perpetual uses the total actual/projected drill, complete andtie-in capital divided by the total of the well initial twelve-month production rate.
RESERVE ESTIMATES: The reserves estimates contained in this presentation represent our gross reserves as at December 31, 2018 and are defined under NI 51-101, as our interest beforededuction of royalties and without including any of our royalty interests. It should not be assumed that the present worth of estimated future net revenues represents the fair market value of thereserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserves estimates of our crude oil, NGL andnatural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and NGL reserves may be greater thanor less than the estimates provided herein.
All future net revenues are estimated using forecast prices, arising from the anticipated development and production of our reserves, net of the associated royalties, operating costs, developmentcosts, and decommissioning obligations and are stated prior to provision for finance and general and administrative expenses. Future net revenues have been presented on a before tax basis.
Estimated values of future net revenue disclosed herein do not represent fair market value.The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to theeffects of aggregation.
Our estimated reserve-based NAV is based on the estimated NPV10 of all future net revenue from our proved plus probable reserves, before tax, as estimated by McDaniel at December 31, 2018,with the estimated value of our undeveloped land, and less net debt. Common share values in our NAV per share metric are calculated using common shares outstanding, net of shares held intrust. Our risked and unrisked reserves & inventory NAV includes unbooked inventory comprised of 43 gross (35.9 net) drilling locations at Edson; 65 gross (65 net) heavy oil drilling locations, 14gross (13.4 net) recompletions in West Central Other and 36 gross (35.1 net) shallow gas recompletions for which reserves have not been assigned.
BOE EQUIVALENTS: Perpetual’s aggregate proved and probable reserves are reported in barrels of oil equivalent (boe). Boe may be misleading, particularly if used in isolation. In accordancewith NI 51-101 a boe conversion ratio for natural gas of 6 Mcf: 1 boe has been used, which is based on an energy equivalency conversion method primarily applicable at the burner tip and doesnot 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 differentfrom the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
The following abbreviations used in this presentation have the meanings set forth below:
bbls barrelsboe barrels of oil equivalentMcf thousand cubic feetMMcf million cubic feetMMBtu million British Thermal UnitsGJ gigajoules
