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PETERS & CO. ENERGY CONFERENCE
JANUARY 2019
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-lookingstatements. Such statements include, but are not limited to, statements pertaining to: Perpetual's spectrum of opportunities that can be optimized throughvariable commodity cycles and anticipated value creation arising from such opportunities; Perpetual's top strategic priorities including reducing debt andrestoring cash flow, growing value and scope of greater Edson liquids-rich gas, maximizing value of Eastern Alberta assets and advancing high impactopportunities; targeting additional asset sales for further balance sheet improvement; anticipated benefits of waterflood projects; reserve and resourceestimates; projected economics for various projects and expenditures; and future capital expenditure levels. These statements are not guarantees of futureperformance 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 unduereliance on these forward-looking statements, which speak only as of the date of this presentation. Unless legally required, Perpetual undertakes no obligationto 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 theestimated timing and amount of future production of natural gas and oil due to numerous factors including permit delays or restrictions, weather, equipmentfailures, delays or lack of availability, unexpected subsurface or geologic conditions, lack of equity or debt capital, increases in the costs of rented orcontracted 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, welland oil field services, taxes, permit fees, regulatory compliance and other costs of operation; decreases in natural gas and oil prices, including price discountsand basis differentials; difficulties in accurately estimating the discovery, volumes, development potential and replacement of natural gas and oil reserves; theimpact of economic conditions on our business operations, financial condition and ability to raise equity or debt capital; variances in cash flow, liquidity andfinancial position; a significant reduction in our bank credit facility's borrowing base; availability of funds from the capital markets and under our bank creditfacility; our level of indebtedness; the ability of financial counterparties to perform or fulfill their obligations under existing agreements; write downs of ourasset carrying values and oil and gas property impairment; the discovery of previously unknown environmental issues; changes in our business and financialstrategy; inaccuracies in estimating the amount, nature and timing of capital expenditures, including future finding and development costs; the inability topredict 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 agiven 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; theimpact of weather limiting or damaging operations and the occurrence of natural disasters such as fires, floods, hurricanes, earthquakes and othercatastrophic 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 thenatural 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 changedaccounting rules under generally accepted accounting principles and IFRS; the amount of future abandonment and reclamation costs, asset retirement andenvironmental obligations; inability to execute strategic plans and realize projected economics, expectations and objectives for future operations and price riskmanagement strategies; and the other risk factors identified in our most recent financial statements and management's discussion and analysis and AnnualInformational Form and our other filings on SEDAR. Unpredictable or unknown factors not discussed herein also could have material adverse effects on ourbusiness and operations and on the forward-looking statements contained herein. 2
Forward Looking Statements
3
Financial Profile (TSX: “PMT”)September 30, 2018 except as noted
Common Shares o/s (1) 60.9 million
Management ownership 34%
Share price (1) $ 0.19
Market capitalization $ 12 million
Net bank debt (2)(4) $ 50 million
TOU share-based loan (3) $ 16 million
Term Loan $ 45 million
Senior unsecured notes $ 32 million
TOU Shares (1.66 million) (3) ($ 30 million)
Net debt (4) $ 113 million
Enterprise value (4) $ 125 million
(1) January 8, 2019 closing market price and common shares outstanding(2) Revolving bank debt, net of working capital (4) at September 30, 2018(3) Loan secured by 1.66 MM Tourmaline Oil Corp. (TSX: “TOU”) shares; closing market price at January 8, 2019 $17.80/share(4) See Non-GAAP measures advisory in this presentation
Financial Profile
4
Q4 2016 to Q4 2018 – Executing the Transition
Dispositions
• Shallow Gas Disposition October 1, 2016
• Sold non-core assets in Q2 2018 for $12 million
Financing Transactions
• $118 million of new funding completed in 2017 to repay 2018 senior notes, extend repayment term and fund growth capital at East Edson
• Reduced TOU share based loan to $16 million - self funded with dividend
Operational
• Drilled 18 wells at East Edson & increased plant capacity to 78 MMcf/d
▪ Grew East Edson production 15% (Q4 2016 to Q4 2018)
• Drilled 10 heavy oil wells & waterflood investment at Mannville
• Grew Mannville heavy oil production 35% (Q4 2016 to Q4 2018)
Marketing
• Secured 5 year term market diversification contract to shift gas price exposure on 40,000 MMBtu/d from AECO to basket of five North American hubs
Positive Impact
• High graded asset base and markets for increased netbacks
• Improved liquidity and debt maturity profile
• 2018 capital program funded from adjusted funds flow
• Enhanced flexibility to manage TOU share investment
Transformational transactions position Perpetual for value creation
5
• Mannville heavy oil
• 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) (80% West Central/20% Eastern Alberta) 9,569 boe/d
Natural Gas (82%) 7,817 boe/d
Oil and NGL (18%) 1,752 bbl/d
P+P Reserves (2) 66.6 MMboe
Reserve to Production Ratio (P+P) (RLI) (3) 17 Years
Bitumen (DPIIP) (4) 1,292 MMbbl
Tourmaline Oil Corp. Shares – 1.66 million (5) $ 30 million
Operating Profile
(1) Q3 2018 production (2) Year End 2017 N1 51-101 McDaniel Report on Reserves Data(3) Year End 2017 Reserves divided by year one production estimate from 2017 McDaniel Report (4) DPIIP (Discovered Petroleum Initially In Place), evaluated by internal qualified reserves evaluator in accordance
with COGE Handbook effective January 1, 2018(5) Closing market price @ January 8, 2019 = $17.80/TOU share
6
(1) Guidance released November 7, 2018
(2) See Non-GAAP measures advisory in this presentation
Capital Spending
($ millions)
2017 2018
Guidance (1)
H1 2019
Guidance (1)
H2 2019
Guidance (1)
2019
Guidance (1)
West Central
Liquids-Rich Gas
$6514 gross
(13.4 net) drills
$121 gross
(1.0 net) drill
(3 frac’s)
$0 - $1facilities
$11 - $122 gross
(2.0 net) drill & frac
1 recompletion
$11 - $132 gross
(2.0 net) drill & frac
1 recompletion
Eastern
Heavy Oil
$85 gross
(4.3 net) drills
$13 - $188 - 12 gross
(7.3 - 11.3 net) drills
6 recompletions
$0 - $1
$10 - $1110 gross
(10 net) drills
10 recompletions
$10 - $1210 gross
(10 net) drills
10 recompletions
Total (1)
$73 $25 - $26 $0 - $2 $21 - $23 $21 - $25
• Q4 2018 capital spending of $4 - $5 million, including frac and tie in of one Edson well and tie in of one Heavy Oil well
• Additional anticipated Asset Retirement spending of $1.5 to $2.0 million in 2019 (2018E: $1.5 - $2.0 million; 2017: $2.3 million)
• 2019 Capital spending funded by adjusted funds flow (2)
Drilling location inventory supports reallocation of 2019 capital to either operating area as commodity prices dictate
7
Capital plan in 2019 balanced between oil and gas but flexible to adjust based on commodity prices
Production Optimized for Value• 16% forecast production growth (Q4 2019 vs. Q4 2016)
• Peak natural gas production during winter months to maximize capture of highest prices
• Summer shut-ins driven by extreme low AECO gas prices shifts portion of natural gas production profile to Winter
• Investing for growth in higher return Mannville heavy oil projects
• Capital spending focused in second half of 2019 to bring on production as commodity prices are anticipated to improve
Production
(1) Average guidance released November 7, 2018
10,500
9,400
8,118
9,876
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 2018E Q1 2019E Q2 2019E Q3 2019E Q4 2019E
Ave
rage
Dai
ly P
rod
uct
ion
(B
oe
/d)
Forecast Production
Gas Production Oil & NGL 2018E 2019 Guidance
(1)
Post Shallow Gas Disposition
• Top quartile operating costs with East Edson concentration combined with infrastructure control, operatorship and low cost culture
• Reduced TCPL tolls through West Central Alberta production concentration
• Royalties driven off AECO pricing while netbacks include market diversification contract uplift
Reducing Costs
• Market diversification contract minimizes AECO exposure and delivers premium price
• Capital timed to peak gas production during winter months and allow declines through Q2/Q3
• Focus capital to higher netback Mannville heavy oil projects
Maximizing Revenue
8
Operating Netback (1)(2)
Increasing operating netbacks driven by:
Maintaining operating netbacks despite lower AECO prices
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 2018E Q1 2019E Q2 2019E Q3 2019E Q4 2019E
$/B
oe
Operating Costs Transportation Costs Cash G&A Interest Royalties RevenuePost Shallow Gas
Disposition
Operating Netback
(1) See Non-GAAP measures advisory in this presentation(2) Q4 2018 and 2019 Forecasts reflects average guidance released November 7, 2018
9
Market Diversification Strategy
Natural gas market shift to diversify portfolio
• Physical delivery at AECO
• Receive Daily Index market price at five downstream delivery points, less published transportation and fuel costs, plus $0.02 USD/MMBtu premium
• 35,000 MMBtu/d effective Nov 1, 2017; 40,000 MMBtu/d on April 1, 2018
• 5 year term, expiring October 31, 2022
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
Advantages to 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
Forecast to enhance funds flow in 2018 & 2019
• 2018E – Incremental revenue of $1.29/GJ on contracted volumes ($0.87/GJ across total natural gas sales) over and above AECO-based sales price
• 2019E – Incremental revenue of $1.20/GJ on contracted volumes ($0.99/GJ across total natural gas sales) over and above AECO-based sales price
Gas market diversification contract forecast to provide significant premium prices over AECO with increased pricing stability
(1) As per Guidance released November 7, 2018(2) Settled incremental contract revenue since inception to December 2018 =
$20.3 million(3) Open Mark to Market incremental contract revenue (as at December 31, 2018)
Jan 2019 to Oct 2022 = $43.7 million
AECO fixed price2% Empress
7%
Dawn16%
Michcon10%
Chicago23%
Malin21%
Natural gas liquids -Condensate
4%
Natural gas liquids - Other2%
Crude Oil - Fixed5%
Crude Oil10%
2019 Price Exposure Net of Royalties
10
2019 Adjusted Funds Flow Guidance (1)(2)
2019 adjusted funds flow guidance: $0.36 - $0.44 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 November 7, 2018 News Release “Outlook” for additional guidance and commodity price assumptions
(3) Nine months ended September 30, 2018 Adjusted Funds Flow = $22.1 million
(4) 2019 forward average prices as at November 7, 2018: NYMEX gas price = US$2.89/MMBtu; WTI price = US$69.81/bbl; WCS differential = US$29.16/bbl; CAD/USD Exchange RateUS$1.00 = $1.30
Guidance assumptions 2018E Guidance (2) 2019 Guidance (2)
Exploration and development expenditures $25 - $30 million $21 - $25 million
Cash costs (1) $14.00 - $15.00/boe $17.00 - $18.00/boe
Average daily production 10,500 – 11,000 boe/d 9,200 – 9,600 boe/d
Average production mix 16% oil and NGL 22% oil and NGL
Adjusted Funds Flow (3) $27 - $29 million $22 – $27 million
(1)(4)
$0.0 $1.0 $2.0 $3.0 $4.0 $5.0 $6.0
Oil & NGL Production (+/- 250 Bbl/d)
Gas Production (+/- 2.5 MMcf/d)
WTI (+/- USD $2.50/bbl)
NYMEX gas price (+/- $0.25 USD/MMBtu)
($ millions)
2019 Adjusted Funds Flow Sensitivities
11Positioned 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 #1
IMPROVE BALANCE SHEET AND MANAGE RISK
13
Sequoia Litigation
Summary Dismissal Application decision anticipated in early 2019
Date Action (1)
Aug 3/18 • PwC initiates litigation against Perpetual and schedules August 30 court date
Aug 27/18 • Perpetual files statement of defense and application for summary dismissal based on determination of threshold issues:➢ Were parties dealing at arm’s length?➢ Is PwC entitled to bring an oppression claim?➢ Breach of public policy claim should be struck➢ Claim made with respect to director duties should be struck
• Judge ruled that there was merit to considering Perpetual’s summary approach in preference of determination of PwC’s full claim
Q4 2018 • PwC agrees to Perpetual’s process application in favour of summary determination of threshold issues
• Perpetual and PwC filed affidavits, conducted cross – examination of affidavits and submitted legal briefs
• Court hearing conducted on November 8 & 9 and December 17
Jan/Feb 2019 • Court decision anticipated
(1) Court documents available at www.perpetualenergyinc.com
14Positive decision on Summary Dismissal Application (with no appeal) would eliminate claim; Negative decision leads to lengthy appeals / full litigation process
14
Sequoia Anticipated Litigation Timeline
Application for Summary Dismissal on threshold issues
Court decision anticipated
PwC may appeal6 months to hear
appeal / render decision
Perpetual may appeal6 months to hear appeal /
render decision
Final Outcome Final Outcome
Full litigation of PwC claim(1 to 3 years)
Favourable Unfavourable
Favourable Favourable
Unfavourable
Q4 2018
Jan/Feb 2019
Q1 - Q3 2019
2020 – 2022
15
Balance Sheet
Security MaturityAmount
($ millions)
Tourmaline Shares (1)
• 1.66 million shares @ $17.80/share N/A N/A $(29.5)
Tourmaline share loan
• 55% loan to value margin trigger TOU Shares Demand $15.6
Net working capital deficiency (3) N/A N/A $7.5
Revolving Bank Debt
• $55 MM borrowing limit
• $3.7 MM letters of credit outstanding 1st Lien May 31, 2019 $42.4
2019 Senior Notes (8.75%) Unsecured July 23, 2019 $14.6
Term Loan (8.1%) 2nd Lien March 14, 2021 $45.0
2022 Senior Notes (8.75%) Unsecured January 23, 2022 $17.9
Net Debt (1)(3) $113.5
Net debt to trailing 12 month adjusted funds flow (2)(3)
• As at December 31, 2018
• As at December 31, 2019
3.8 times
4.3 times
(1) As of September 30, 2018, adjusted for market price of TOU share investment January 8, 2019
(2) As per Guidance released November 7, 2018
(3) See Non-GAAP measures advisory in this presentation
Year End 2018 Net Debt to TTM adjusted funds flow (2) ratio forecast at 3.8 times
16
2019 Financing Initiatives
Available liquidity (1)(2) of ~$23 million
• Comprised of available bank line plus TOU share investment, net of TOU share-based loan
• Building additional liquidity through the first half of 2019 with limited capital spending and expected adjusted funds flow (3) of $10 to $14 million
2019 Senior Notes repayment
• $14.6 million due July 23, 2019
• Bank lenders approval required to repay subordinate debt, including 2019 Senior Notes
Credit facility term extension beyond May 31, 2019
• Semi-annual revolving bank debt borrowing base redetermination (scheduled for May) to be accelerated to Q1 following Sequoia litigation Summary Dismissal decision
• Clarity on Summary Dismissal Application decision preferred by bank lenders
• Term extension requires acceptable plan for 2019 Senior Notes management
Options for funding 2019 Senior Notes repayment
• Issuance of additional new junior debt
• Asset sales / TOU share sales
• Market diversification contract monetization
Top Priority to Extend Debt Repayment Profile
(1) Bank Debt at September 30, 2018, adjusted for market price of TOU share investment at January 8, 2019
(2) See Non-GAAP measures advisory in this presentation
(3) As per Guidance released November 7, 2018
STRATEGIC PRIORITY #2
GROW VALUE OF GREATER EDSON LIQUIDS-RICH GAS
1866 (63.3 net) locations booked in 2017 Year End McDaniel reserve report
4 ERH locations ready to execute with 2 planned for Q4 2019
Edson Activity
ERH pad• 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
19Infrastructure 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
14,0002
01
1
20
12
20
13
20
14
20
15
20
16
20
17
20
18
E
20
19
E
Cu
mu
lati
ve P
rod
uct
ion
(M
bo
e)
Bo
e/d
20
Edson Type Curves
Year End 2017 reserve value reflects strong capital efficiencies & low operating costs
McDaniel YE 2017 TPP West Type Curve Economics (1)
Price Deck McDaniel January 1/2018
Capital (D,C & T) $ 4.5 MM
NPV @ 10 % $ 3.5 MM
ROR 45%
F&D $ 6.57/ boe
Capital Efficiency $7,800 boe/d
Payout 2.1 Years
Recycle Ratio 2.1
Year 1 Pricing $2.13/ GJ (AECO); $54.06/bbl NGL
Operating Costs $1.57/ 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 1.9 MMcf/d11.75 bbl/MMcf NGL/condensate
2P Reserves 4.1 Bcfe per well
Well defined TPP type curves(1) provide reliable forecasts ERH wells length-adjusted to increase rate & reserves per wellMcDaniel prices provides compelling investment thesisCurrent 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 2017 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 - Monobore design proved up for 1,700 metre type curve length wells
• 2018/2019
Optimized monobore design with consistent rig program and longer laterals
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
21
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 2017 PDP forecast for wells onstream less than 12 months). The ERH estimate is based on future estimates of proven undeveloped locations from the McDaniel 2017 report.
East Edson Wilrich Capital Efficiency
Targeting further improvements in capital efficiency
22Higher production over fixed cost base drives top quartile operating cost structure
Top Quartile Operating Cost Structure
(1) See November 7, 2018 news release “Outlook” for Operating Cost guidance assumptions
$0.00
$3.00
$6.00
$9.00
$12.00
$0
$500
$1,000
$1,500
$2,000
May
-14
Jun
-14
Jul-
14
Au
g-1
4
Sep
-14
Oct
-14
No
v-1
4
De
c-1
4
Jan-
15
Feb
-15
Ma
r-1
5
Apr
-15
May
-15
Jun
-15
Jul-
15
Au
g-1
5
Sep
-15
Oct
-15
No
v-1
5
Dec
-15
Jan-
16
Feb
-16
Mar
-16
Apr
-16
May
-16
Jun
-16
Jul-
16
Au
g-1
6
Sep
-16
Oct
-16
No
v-1
6
Dec
-16
Jan-
17
Feb
-17
Mar
-17
Apr
-17
May
-17
Jun
-17
Jul-
17
Au
g-1
7
Sep
-17
Oct
-17
No
v-1
7
De
c-1
7
Jan-
18
Feb
-18
Ma
r-1
8
Apr
-18
May
-18
Jun
-18
Jul-
18
Au
g-1
8
Sep
-18
Oct
-18
No
v-1
8
Dec
-18
Q1
20
19
E
Q2
20
19
E
Q3
20
19
E
Q4
20
19
E
Op
erat
ing
Cost
s/B
oe
($/B
oe)
Mo
nth
ly O
pe
rati
ng
Co
sts
($00
0's)
East Edson Operating Costs (1)
Monthly Operating Costs Operating Costs ($/Boe)
STRATEGIC PRIORITY #3
GROW VALUE OF EASTERN ALBERTA PORTFOLIO
24
Eastern Alberta – Mannville Heavy Oil
2019 Capital Program targets development drilling, exploration targets and waterflood optimization projects
(1) Parameters as per 2017 NI 51-101 McDaniel Report in accordance with COGE Handbook effective Jan 1, 2018. Recovery factor based on aggregate McDaniel TPP + Cum produced to date divided by aggregate DPIIP. Initial rates as per range in PPUD bookings.
Mannville Q4 2018 Production
•Area production of 1,800 boe/d (70% oil)
• From 6 oil pools, production of 1,300 boe/d (96% oil)▪ Increase of 35% from Q4 2016
• Power Generation of ~800 kW/d improves gas production netbacks
Access to Large Oil Resource
•> 190 MMbbl Discovered Petroleum Initially In Place(1)
• 4.7 MMbbl produced to date (<3%)
• 2.9 MMbbl remaining TPP reserves (4% recovery factor)(1)
Low cost HZ development
• $0.9 MM DC&T per single lateral well(1)
•Average expected initial rate ~50-120 bbl/d(1)
•Multi-lateral drilling (4 to 8 laterals) is planned for execution in 2019 driven by success of 3 leg re-entry in Q4 2018
2018 drills 2019 drillsProducing poolsExploration pools
2018 Capital Program▪ 6 (6 net) development wells▪ 1 re-entry adding 3 laterals to an existing well2019 Capital Program▪ 10 (10 net) wells, including multi-laterals and up to 3 exploratory▪ 1 re-entry adding 2 laterals to an existing well
2511 (10.0 net) locations booked in McDaniel Year End 2017 Reserve Report Unbooked Inventory of 31 (30.4 net) locations
Well Economics
Capital (D,C & T) $0.9 MM
NPV @ 10 % $1.5 MM
ROR 184 %
F&D $8.35 / boe
Payout 0.9 years
Capital Efficiency(First Year)
$10,500/boe/d
Recycle Ratio(First Year)
3.9
Oil over shakers while drilling Multi-well Pad Site Mannville Multi-well Battery
Assumptions (1)
2018 Pricing(McDaniel Jan 2018 forecast)
CAD$47.90/bbl wellhead heavy priceWTI US$58.50/bbl; WCS CAD$51.90/bbl; Offset CAD$4.00/bbl
Operating Costs$6.03/boe (first year) &$13.83/boe (lifetime)
Average Well IP 100 bbl/d to 59 bbl/d in year 1
Ultimate Recovery 100 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 2017 N1 51-101 McDaniel Report on Reserves Data
0
200
400
600
800
1/1/2013 1/1/2015 1/1/2017 1/1/2019 1/1/2021
Oil
Rat
e, b
bl/
d
Regional Lloyd Lower
McDaniel 2017 Oil Rate Base Decline
McDaniel PPDP
YE 2017
Wat
erf
loo
d c
om
me
nce
d
26
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 2017 NI 51-101 McDaniel in accordance with COGE Handbook effective Jan 1, 2018
0
200
400
600
800
1/1/2013 1/1/2015 1/1/2017 1/1/2019 1/1/2021
Oil
Rat
e, b
bl/
d
Regional Lloyd Mid
Oil Rate Oil Base Forecast McDaniel 2017
McDaniel PPDP
YE 2017
Wat
erf
loo
d c
om
me
nce
d
0
200
400
600
800
1000
1/1/2013 1/1/2015 1/1/2017 1/1/2019 1/1/2021
Oil
Rat
e, b
bl/
d;
Channel
Oil Rate MD 2017 PPDP MD 2017TPP Oil Rate without new drill
DPIIP (2)
(MMbbl)
Cumulativeproduction to YE 2017
(MMbbl)
TPP Reserves booked at YE 2017 (1)
(MMbbl)
Implied Recovery
Factor(%)
133 3.4 1.7 4%
Upper Mannville B Pool consists of 3 geological units, all under waterflood
Wat
erf
loo
d c
om
me
nce
d
McDaniel PPDP
YE 2017
0
200
400
600
800
1/1/2013 1/1/2015 1/1/2017 1/1/2019 1/1/2021
Oil
Rat
e,
bb
l/d
Upper Mannville I2I Pool
Oil Rate Oil Base Decline Oil Rate Without Infill McDaniel PPDP 2017
McDaniel PPDP
YE 2017
27
Mannville Heavy Oil Pools Waterflood Response
Positive performance evident in all pools under waterflood
Wat
erf
loo
d c
om
me
nce
d
0
100
200
300
400
1/1/2013 1/1/2015 1/1/2017 1/1/2019 1/1/2021
Oil
Rat
e, b
bl/
d;
Upper Mannville T8T Pool
Oil Rate MD 2017 PPDP
McDaniel PPDP
YE 2017
Pool DPIIP (2)
(MMbbl)
Cumulativeproduction to
YE 2017(MMbbl)
TPP Reserves booked at YE
2017 (2)
(MMbbl)
Implied Recovery Factor(%)
Sparky I2I (1) 38 0.8 0.6 4%
Upper Mannville T8T 11 0.2 0.5 7%
(1) Net working interest of 100% since acquisition of partners 33.3% WI in September 2018(2) DPIIP (Discovered Petroleum Initially In Place) and TPP Reserves, as per 2017 NI 51-101 McDaniel in accordance with COGE Handbook effective Jan 1, 2018
Wat
erf
loo
d c
om
me
nce
d
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
29Bitumen 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
Bitumen
(1) DPIIP (Discovered Petroleum Initially In Place), evaluated by internal qualified reserves evaluator in accordance with COGE Handbook effective January 1, 2018
30
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 utilizing solvent is 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, 2018
31Conductive heating with water or solvent injection for mobility and pressure support
First stage of pilot – single well Cyclic Heat Stimulation completed in Q2 2017
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 Q1 2017 of varying heat stimulation and solvent parameters
Exceeded cumulative oil production expectations by >100%
Second stage of pilot
Solvent screening study underway; Alternative heat delivery systems being evaluated
Second stage pilot design guided by first stage learnings and economic viability assessment to be scoped in 2019; Decision toproceed with second stage of pilot will follow
Pilot results will drive full scale development potential assessment
Top Gas
Heaters / Injectors
Oil
Producer
LEAD Pilot Stage 2 Configuration
LEAD Process Technology PilotLow Pressure Electro-Thermally Assisted Drive
INVESTMENT THESIS
COMPELLING DISCOUNT TO NET ASSET VALUE
TORQUE TO GAS PRICE RECOVERY
33
Sum of the Parts – Year-End 2017
Year-End 2017 Reserve-Based NAV = $5.68/share
(1) Net asset value per share based on 59.3 million shares outstanding. Reserve valuation based on NPV10% McDaniel reserves and pricing; Independent third party undeveloped land assessment as at December 31, 2017
(2) As per (1) above; Undeveloped land replaced with risk-discounted unbooked inventory in East Edson and Mannville only; West Central and Eastern Alberta Other unbooked inventory locations captured only through undeveloped land valuation outside East Edson and Mannville; Includes incremental TOU share value based on 12 month TOU analyst consensus target price of $30.44/share
(3) As per (1) and (2) above; Unrisked unbooked inventory in East Edson and Mannville only; See oil and gas advisories in this presentation
Expect future PPDP growth & TPP reserve replacement through cycling in of East Edson technical reserves from unbooked inventory
▪ YE 2017 year-over-year reserve growth: 100% PDP; 44% PPDP; 9% TPP (As per 2017 and 2016 McDaniel NI 51-101 Report)
Unbooked Inventory Unbooked Inventory
Net Bank Debt
34
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 heavy oil and natural gas focused resource-style
plays
Track Record of Operational Performance
Execution and operational excellence in chosen strategies
Multiple Levers to Manage Balance Sheet
2019 capital program funded by adjusted funds flow
Optionality to meet obligations as they come due
Value
Attractive share price
Trading significantly below Reserve-based net asset value
Tremendous leverage to gas prices with asset mix and TOU exposure
Market diversification natural gas contract provides premium NYMEX based pricing across five markets
through to November 2022 minimizing exposure to AECO gas price
High impact value potential from medium to long term assets
Spectrum of opportunities for value creation upon emergence from bottom of commodity price cycle
35
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
36
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 of payments”, “net workingcapital deficiency (surplus)”, “net debt and net bank debt”, “operating netback”, “realized revenue” and “enterprise value” used in this MD&A are not recognized under GAAP. Management believesthat in addition to net income (loss) and net cash flows from (used in) operating activities as defined by GAAP, these terms are useful supplemental measures to evaluate performance. Users arecautioned however that these measures should not be construed as an alternative to net income (loss) or net cash flows from (used in) operating activities determined in accordance with GAAP asan indication of Perpetual’s performance and may not be comparable with the calculation of similar measurements by other entities. Additional information on these Non-GAAP measures, includingreconciliations to applicable GAAP measures, are included in the Company’s most recently filed Management Discussion and Analysis and may be 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 to financecapital expenditures, expenditures on decommissioning obligations and meet its financial obligations. Adjusted funds flow is calculated based on cash flows from (used in) operating activities,excluding changes in non-cash working capital and expenditures on decommissioning obligations since Perpetual believes the timing of collection, payment or incurrence of these items 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. Expenditures on decommissioningobligations are managed through the capital budgeting process which considers available adjusted funds flow. The Company has also deducted the change in gas over bitumen royalty financingfrom 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 credits and are recorded as areduction to the Corporation’s gas over bitumen royalty financing obligation in accordance with IFRS. Additionally, the Company has excluded payments of restructuring costs associated with thedisposition of the shallow gas assets on October 1, 2016 (the “Shallow Gas Disposition”), which management considers to not be related to cash flow from operating activities. Restructuring costsinclude employee downsizing costs and surplus office lease obligations. Commencing in the first quarter of 2018, the Company no longer excludes ‘exploration and evaluation – geological andgeophysical costs’ (Q2 2018 – nil; and Q2 2017 – recovery of $0.02 million) from the calculation of adjusted funds flow as these costs are no longer significant to the Company’s business. Thecalculation of adjusted funds flow 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 ofshares outstanding used in calculating income (loss) per share. Adjusted funds flow is not intended to represent net cash flows from (used in) operating activities calculated in accordance withIFRS.
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 issued underthe 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, productionand 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 in the 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). Netdebt 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 senior notes, reduced forthe 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 borrowing capacity. Net debt toadjusted 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 liabilities related tothe Corporation’s risk management activities, current portion of gas over bitumen royalty financing, TOU share investment, TOU share margin loan, revolving bank debt, and current portion ofprovisions.
Operating netback: Perpetual considers operating netback to be an important performance measure as it demonstrates its profitability relative to current commodity prices. Operating netback iscalculated 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. Operatingnetback 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, crudeoil and foreign exchange contracts but excludes any realized gains (losses) resulting from contracts related to the disposition of the 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 represent the totalfunds from equity and debt received by the Corporation upon issuance.
37
Oil and Gas Advisories
OIL AND GAS ADVISORIES: The presentation refers to F&D (finding and development costs), ROR (rate of return), payout and recycle ratio which have been prepared by management and areused to measure performance. These terms do not have standardized meanings or standard calculations and are not comparable to similar measures used by other entities. In this presentationinternal 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 refers to the time required to pay back the capitalexpenditures (on a before tax basis) of a project. The presentation also refers to capital efficiency which is defined as a type of capital efficiency that measures the cost to add an incrementalbarrel of flowing production. Specifically, for the average production efficiencies of our plays, Perpetual uses the total actual/projected drill, complete and tie-in capital divided by the total of thewell initial twelve-month production rate.
RESERVE ESTIMATES: The reserves estimates contained in this presentation represent our gross reserves as at December 31, 2017 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 presented in the tables above representsthe fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserves estimates ofour crude oil, NGL and natural 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 NGLreserves may be greater than or 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 year-end, with theestimated 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 in trust. Ourrisked and unrisked NAV includes Unbooked inventory comprised of 47 gross (40.4 net) drilling locations at East Edson and 31 gross (30.4 net) drilling locations at Mannville, for which reserveshave 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