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Annual General Meeting
of ShareholdersMay 7, 2020
2
US Crude Oil DemandBelow 2019 Levels and 5-Year Range
• US crude oil demand is 31% lower now than compared to 2019 demand levels and 28% lower
than the average of the last five years
7.8 MMbbl/d less
than March 4, 2020
Source: Bloomberg, TD Securities; April 29, 2020
3
Crude Oil PricingAll Major Benchmarks Down
• WTI prices were 44% lower as at April 29, 2020 compared to just one month prior and 84%
lower than one year previous years
Source: Bloomberg, TD Securities; April 29, 2020
44% Lower
than the
previous
month
4
Source: CIBC World Markets; April 30, 2020
US Drilling Rig CountCrude Oil Drilling Activity Falls
• US crude oil drilling rigs fell from 665 on March 16, 2020 to 361 on April 27, 2020, a reduction
of 46% in just 6 weeks
Down
46%
5
US Natural Gas DemandConsistent Demand
Source: Bloomberg, TD Securities; April 30, 2020
• Natural gas demand levels are approximately in-line with previous years and have not shown
signs of non-seasonal decline
Residential / Commercial Natural Gas Demand
Industrial Plants Natural Gas DemandElectric Power Plants Natural Gas Demand
Gas demand at
5-year average
Gas demand at
5-year averageGas demand above
5-year average
6
US Natural Gas SupplyMarcellus
Marcellus Production
Source: Bloomberg, TD Securities; April 23, 2020
Drop of >1Bcf/d
from peak levels of
production
7
US Natural Gas SupplyUtica
Utica Production
Source: Bloomberg, TD Securities; April 23, 2020
Gas production
off by >1 Bcf/d
from peak levels
of production
8
US Natural Gas SupplyPermian
Permian Production
Source: Bloomberg, TD Securities; April 23, 2020
Gas production
growth is
flattening
9
US Natural Gas Production Year-over-Year Key Play Production Growth Slowing
• Since Q4 2019, the year-over-year growth in natural gas production from these key US plays has been
declining
• At the current pace of decline combined with drilling rig count reductions in the largest contributor in
annual growth (Permian), total US natural gas production is shrinking on key plays
Source: Bloomberg, TD Securities; April 30, 2020
US Key Plays – Natural Gas Production
From March 4,
2020 to April 30,
2020, US gas
production from
these key plays fell
by 1.7 bcf/d
$1.75
$2.00
$2.25
$2.50
$2.75
$3.00
$3.25
Pri
ce (
US$
/MM
BTU
)
Month
Current Fwd Strip 6 Months Ago Year Ago Fwd Strip
10
NYMEX Forward Price StripSignificant Improvement in NYMEX Prices
• Forward strip prices at NYMEX reversed a drop from earlier in 2020 with current forward
strip prices for October 2020 exceeding the strip from one year ago
• Current forward strip places NYMEX at over USD$3.00 by the end of 2020 and remaining
above previous strip prices for the remainder of 2021
Source: NGX; May 6, 2020
NYMEX Forward Strip Pricing
11
Canadian Natural Gas StorageWestern Canada Below 5-Year Average
Source: Bloomberg, Bentek, TD Securities; April 30, 2020
Western Canada Natural Gas Storage (bcf)
• Natural gas storage levels remain low, with storage levels as of April 30, 2020 an additional
2% lower than 2019’s remarkably low levels
2020 natural
gas storage
levels are at a
5-year low
12
AECO Forward Price StripSignificant Improvement at AECO Prices
AECO Forward Strip Pricing ($CAD/Mcf)
Source: NGX; May 6, 2020
• Improvement in the current forward strip price at AECO for 2020 and 2021 compared to one
year ago and average over CAD$2.50/Mcf for the next 24 months
$0.75
$1.00
$1.25
$1.50
$1.75
$2.00
$2.25
$2.50
$2.75
$3.00
$3.25
Pri
ce (
C$
/MC
F)
Month
Current Fwd Strip 6 Months Ago Year Ago Fwd Strip
$0.00
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$ /M
cf
Station 2 Historical and Forward Strip Pricing (April 24, 2020)
Station 2 PricingStation 2 – Surviving the trough
July 2017 to Oct 2019
(28 Months)
Avg Price $0.98/Mcf
Nov 2020 to Oct 2023
36 Months
Avg Strip $2.46/Mcf
historical forecast
3 year strip is
more than 200%
better than last
28 months
Investor UpdateMay 7, 2020
To establish PONY as the
low-cost, secure supplier of
Clean Natural Gas energy to
Canada and the World.
Vision Statement
Why we do what we do…
We believe:
• world demand for clean and reliable energy is rapidly growing
• technological advancements makes our energy cost competitive on a world scale
• in developing our world-class resource using the highest standards, environmentally and socially
• the world trusts doing business with Canada
Our Mission is to establish PONY as a low-cost supplier
of clean natural gas to Canada and the world.
16Source: BP Global Energy Outlook, 2019*Renewables includes wind, solar, geothermal, biomass, and biofuels
Percentage of Global Energy Needs
Renewables
Hydro
Nuclear
Coal
GasOil
Source: US Energy Information Administration (EIA) June 4, 2019
229
161 157
139
117
0
50
100
150
200
250
Coal Diesel Gasoline Propane Natural Gas
Clean-Burning Natural GasLowest GHG Emissions
Po
un
ds
of
CO
2Em
issi
on
s /
MM
Btu
Compared to clean
burning natural gas,
CO2 emissions from
coal are 96% higher
while diesel emissions
are 37% higher
PONY supplements diesel
fuel with natural gas fuel for
completion operations which
reduces per well capital costs
and lowers PONY’s GHG
emissions
Converting coal-fired electricity
generation plants to natural gas
(including LNG) reduces GHGs
by 48%...a REAL solution to
lowering emissions
17
Global LNG MarketDemand Growth
1 - Source: BP statistical review, Kepler Cheuvreux estimates (Equity Research Q&A Report, April 23, 2019)
Glo
bal LN
G D
em
and
(1)
181
221240 241 236 240 245
257
287
308323
340357
374393
413433
0
100
200
300
400
500
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
.
Global LNG demand could reach 433 Mtpa (57 Bcf/d) in 2025
Global LNG
demand increased
78%2009 - 2019
Global LNG
demand forecast
to increase
34%2020 – 2025(1)
Mtpa (Million Tonnes per Annum)
is a typical measurement unit in
LNG markets for production
Approximate conversion:
1 mtpa = 0.132 Bcf/d
1 Bcf/d = 7.576 mtpa
24
29
32 32 31 32 3234
38
4143
4547
49
52
55
57
Mtpa
Bcf/d
Bcf/d
Mtpa
18
Natural Gas Pipeline
Coastal GasLink Pipeline
LNG Projects Capacity
LNG Canada Shell, Petronas, Mitsubishi, Petro-
China, KOGAS
• Phase 1 - under construction
1.9 – 3.8 Bcf/d
Woodfibre LNGPacific Oil & Gas
(FID expected in 2020)0.3 – 1.0 Bcf/d
Tilbury LNG FortisBC
• Phase 1 - under construction
• Phase 2 - construction 2022
0.13 – 0.5 Bcf/d
TOTAL 2.3 – 5.3 Bcf/d
LNG Canada (Shell)
Export Facility
(Under Construction)
Woodfibre LNG
(Pacific Oil & Gas)
Tilbury LNG
(FortisBC)
Coastal GasLink
Proposed West Coast LNG & LPG Projects Game Changers
T-North Enbridge
Mainline
T-South Enbridge
Mainline
36” and 30”
19
5.3 Bcf/d represents over 30%of current Canadian natural gas
production removed from
domestic supply
LNG Canada Construction UnderwayKitimat, BC Site
November 2019
August 2018
LNG Canada’s export
facility at Kitimat has
been under construction
since October 2018
20
“In 2019, the global LNG market continued to
evolve according to the latest Shell LNG Outlook,
with demand increasing for LNG and natural gas
in power and non-power sectors. Record supply
investments have been made to meet people’s
growing need for the most flexible and cleanest-
burning fossil fuel. In China, LNG imports
increased by 14% in 2019, as that country
continues to value improved urban air quality.”
Peter Zebedee, CEO, LNG Canada
February 24, 2020
Alberta Natural Gas MarketContinued Demand Growth
0.0
2.0
4.0
6.0
8.0
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023
Oilsands
Industrial / Petrochemical / Other
Electricity
Generation (including Coal-to-Gas Conversions)
Alberta is expected to
increase natural gas
consumption by over 45%
between 2018 and 2023
201
5
Natu
ral G
as
Dem
an
d (B
cf/d
)
20150.0
2.0
4.0
6.0
8.0• Significant demand growth taking place in Alberta
• Steady phase-out of coal in electrical generation
• Increased demand for natural gas in the oilsands
• Power demand continues to rise
• This does not include the impact of west coast LNG
exports
2015 2030
Electricity Generation Sources in Alberta
Source: CAPP, AER
51% Coal
40% Natural Gas
9% Renewables
70% Natural Gas
30% Renewables
75% increase
in natural
gas demand
21
Corporate ProfileTSX: PONY (as at May 6, 2020)
Note: As at March 26, 2020
* RLI (Reserve Life Index) is calculated using 2019 year-end 2P reserves divided by 2019 average daily production volumes
2019 2P Reserve Life Index* 64 Years
Enterprise Value $540 million
Common Shares Outstanding 161 million
Q1 2020 Average Daily Production 319 MMcfe/d (53,141 boe/d)
30-day Average Daily Trading Volume 1.6 million shares per day
1H 2020 Capital Budget $25-30 million
PONY Ownership• Employees (65 full-time; via company savings plan) 3.4 million
• Officers (company savings plan and personal holdings) 2.7 million shares
• Annual Shares Purchases (company savings plan; April ‘19 – April ‘20) 1.9 million shares
22
World Class ResourceMontney Pure Play
1) As at December 31, 2019; see Advisories Section
Natural Gas Pipeline
Coastal GasLink Pipeline
Asset• The Montney is the most economic
natural gas and natural gas liquids play
in Canada
• 290 net sections (185,704 net acres) of Montney lands
• 6,800 Bcfe (1,133 MMboe) Total Proved
plus Probable reserves(1)
• 880 Bcfe (146 MMboe) of Proved
Developed Producing reserves
Strategic Advantages• Firm transportation in-place allowing
access to a diversity of markets,
reducing commodity pricing risk
• De-risked reserves with deep
inventory of future drilling locations
23
2020 Capital ProgramDisciplined Capital Investment
• Investing $25 - $30 million for 1H of 2020
• Q1 capital spending of $21 million
• PONY will review capital budget at mid-year to determine
appropriate 2H 2020 spending levels
• Current program includes:
• Drilling 10 gross (4 net) wells
• Completing 2 gross (2 net) wells
24
Montney Pure PlayLocation, Location, Location
LEGEND
Painted Pony Lands
Painted Pony / AltaGas Facilities
Third-Party Facilities
Enbridge T-North Pipeline
Secondary Pipelines
PONY’s Montney
Sweet Spot is:
• 4x thicker than the Marcellus at greater than
300 meters (approximately 1,000 ft.) thick
• a continuous sweet natural gas-saturated
zone with no associated or underlying water
• highly over pressured on PONY lands with
up to 1.8x over-pressured reservoir
Kobes
Blair
Daiber
Beg
Jedney
West
BlairCypress
Painted Pony Lands
Gas/Liquids Processing Plant
Dry Gas Processing Plant
Enbridge T-North Pipeline
TC Energy North Montney Mainline Pipeline
Secondary Pipelines
Townsend
Dry Liquids
South
Townsend
25
North Kobes
Facility
AltaGas
Townsend
Plant
Kanata Daiber
Plant
Daiber South
Facility
Daiber West
Facility
Daiber North
Facility
AltaGas Blair
Plant
West Blair
Facility
North River
Jedney Plant
Jedney
Facility
-
250,000
500,000
750,000
1,000,000
1,250,000
1,500,000
1,750,000
2,000,000
2,250,000
Painted Pony
Other Producers
Source: GeoScout; As at March 16, 2020
60 of top
100 wells
are PONY
wells!
Top 100 Wells - Northern Montney Field (sample set of 1,448 wells)
Cu
mu
lati
ve N
atu
ral G
as
(Mcf
)
The Sweet SpotNorth Montney 6-Month Cumulative Production Volumes
PONY has the best well
in North Montney with
6-month average daily
production rate of more
than 11 MMcf/d
26
BRITISH
COLUMBIA
North
Montney
ALBERTA
1.3x1.5x
3.3x
4.3x
0.0x
1.0x
2.0x
3.0x
4.0x
5.0x
Proved Developed Producing Total Proved Proved plus Probable
2019 3-Year Weighted Average
2019 ReservesSignificant Resource, Significant Value
0.9
2.1
3.8
Proved Developed Producing
(PDP)
Proven Undeveloped
(PUD)
Probable
2019 Operating Netback
$1.66/Mcfe
2019 PDP Finding, Development
& Acquisition Cost
$1.26/Mcfe
=2019 PDP
Recycle Ratio
1.3x
Tcfe Tcfe
Tcfe
27
Total Proved(1P)
3.0 Tcfe(44% of 2P)6.8 Tcfe
Total 2P Reserves
2019 Future Development
Capital was reduced by more
than 2019 capital spending, a
significant achievement for
PONY but which makes the 1P
and 2P recycle ratios incalculable
Maintained 1P reserves year-over-
year with a 2019 net capital
program of $42 million while
reducing FDC costs by $171 million
28
0
2
4
6
8
10
12
14
Probable Total Proved
12.3
9.5
6.8
6.3
0.2 0.2 0.20.20.20.30.4
0.90.6 0.5 0.5 0.5
1.61.2 1.1
1.9
2.5 2.42.0 2.0
4.3 4.2 4.1
5.2
4th largest domestic natural gas
reserves of any publicly-traded
company in Canada
2019 Natural Gas ReservesFourth-Largest 2P Natural Gas Reserves
Source: Company Reports, TD Securities; excludes NGLs, crude oil, and Bitumen
2.0Pro
ved
plu
s P
rob
ab
le R
ese
rves
(Tcf
)
Canbriam TransactionClosed June 2019
Montney Landholdings
Painted Pony Energy (185,704 net acres)
• Canbriam Energy (171,436 net acres)
Major Gas Pipelines
Alaska Highway
Valuation Metrics(based on $1 billion Canbriam valuation)
Canbriam $5,833/acre
PONY $5,833/acre x 185,704 acres = $1.1 billion
$1.1 billion - $320 million net debt = $780 million
$780 million / 161 million shares = $4.84/sh
Canbriam $4.34/boe of 1P reserves
PONY $4.34 x 496 MMboe (1P) = $2.15 billion
$2.15 billion - $320 million net debt = $1.83 billion
$1.83 billion / 161 million shares = $11.38/sh
29
• Canbriam Energy sold to Pacific Oil & Gas
for $1 billion
• Offsetting acreage analog for PONY
• Validates land sale prices in NEBC
In 2019 PONY sold
8,460 net acres for
$45 million or
$5,319/acre, further
validating value of
acreage
Market DiversificationNatural Gas Physical Delivery
Dawn
NYMEX
PONY Sales / Pricing Exposure
Medicine
Hat
AECO
Station
2
Sumas
LNG
Export
Mexico
Export
U N I T E D S T A T E S
C A N A D A
M E X I C O
PONY
Growing US Natural Gas ExportsExports to Mexico 5.2 Bcf/d
LNG 8.2 Bcf/d
2020 LNG additions 1.6 Bcf/d
Total (end 2020) 15 Bcf/d
MEDICINE HAT
10 MMcf/d to Methanex’s
methanol plant in Alberta
increasing to 20 MMcf/d in
2021 and 50 MMcf/d in 2023
SUMAS Market
33 MMcf/d
Western Markets
St. 2 & AECO174 MMcf/d
DAWN Market
88 MMcf/d
30
Transportation Firm Transportation & Toll Advantage to West Coast
Enbridge
T-North
(St 2 or
Sunset Creek)
$0.24/Mcf
PONY has a net $0.35/Mcf
transportation toll
advantage delivering natural
gas to Sunset Creek (start of
the Coastal Gaslink pipeline)
TC Energy
NMML
$0.59/Mcf
to Sunset
Creek
31
$0
$2,000,000
$4,000,000
$6,000,000
$8,000,000
$10,000,000
$12,000,000
$14,000,000
Drill
and C
om
ple
tion C
ost
($)
Perf & Plug Systems21 wells
D&C cost $7.7 million
2011 2012 2013 2014 2015 2016 2017
1st Generation Open
Hole Ball Drop System33 wells
D&C cost $6.9 million
Current Generation Open Hole Ball Drop
System
131 wellsDrill & Complete cost $4.3 million
As capital well costs fell, production type curves
dramatically improved
Well Cost (drill + complete)
Historical CostsDrilling & Completions Efficiency
2018
$4.3 mm
average
(1) Total 2P - Total Proved Plus Probable
2019
Continued type curve
improvement with
average Total 2P(1) well
booking of 9.2 Bcfe/well
32
Management
Type Curve
increased 50%
2,700 meter long lateral wells
0
2
4
6
8
10
12
14
16
0 6 12 18 24
Months on Production
Blair Long Lateral WellsEncouraging Performance
Using longer laterals, PONY has
the opportunity to improve
capital efficiency to
approximately $6,000/boe/d
Townsend
South
Townsend
Beg
Jedney
Cale
nd
ar
Day N
atu
ral G
as
Rate
(M
Mcf
/d)
33
1,800 m standard lateral length management production type curve
2,700+ m long lateral length wells(see advisories for well locations)
2,700 m lateral wells(see advisories for well locations)
Eight long lateral wells of
2,700 meters have
consistently outperformed
management’s 1,800 meter
lateral length production
type curve for the Blair /
Daiber areaBlair
Daiber
Townsend
South
Townsend
West
Blair
Cypress
Kobes
Single Well Economics* IRR NPV10 Pay Out
Daiber 1,800 m lateral(dry)
127% $10.1 mm 1.0 years
Daiber 2,700 m lateral(dry)
183% $16.2 mm 0.8 years
Blair 1,800 m lateral (lean; 15 bbls/MMcf)
74% $7.4 mm 1.5 years
Blair 2,700 m lateral (lean; 15 bbls/MMcf)
116% $12.5 mm 1.1 years
Single Well Economics by AreaDriving Increased Capital Efficiencies Through Longer Lateral Wells
Well Capital Costs
1,800 meter lateral
Total $4.9 million
2,700 meter lateral
Total $5.8 million
PONY’s longer laterals at 2,700+
meters deliver higher rates of return
than previous standard length
laterals drilled to 1,800 meters.
34
*Single Well, Half Cycle Economics based on flat pricing of:
WTI US$35/bbl, AECO $2.60/Mcf, NYMEX US$2.50/MMBtu, FX $0.72
Longer lateral wells require
approximately 20% more capital
but deliver, on average, a 45%
increase in booked reserves
ESG Environmental, Social, Governance
Social
35
With Indigenous Communities, PONY strives to:
• Grow relationships with local Indigenous neighbours to instill trust and earn support for current and future operational activities
• Strengthen employee effectiveness to create a culture of awareness and promote cohesiveness when working with our
Indigenous neighbours
• Increase local Indigenous opportunities for employment and contracts that deliver mutual benefits and promote sustainability
PONY supports a number of social initiatives and community charities:
• Hopethiopia
• Calgary Urban Project Society (CUPS)
• Habitat for Humanity
• KidSport Canada
• Adolescent Mental Health Foundation
Social Responsibility
• YWCA Calgary
• Children’s Wish Foundation
• The Salvation Army
• Children’s Cottage Society
• Teen Challenge Alberta
• Halfway River First Nation Rodeo
• Spirit of the Peace Pow Wow
• Blueberry River First Nation Rodeo
• Halfway River First Nation Hockey Team
• Peace Aboriginal Youth Hockey Team
• PONY is an industry leader in the use of the ‘EPOD Solar Hybrid Power Generation and Instrument Air Systems’ on well
sites, which eliminates vented GHG emissions from that location
• All new PONY wellsite infrastructure will have zero venting protocol greatly reducing future emissions
• Power generation on smaller sites and minor expansion projects use ‘EYOY Methanol Fuel Cell/Solar Hybrid Systems’ to
electrify choke valves, chemical pumps and fluid dump valves which minimizes vented volumes and total GHG emissions
• PONY substitutes clean-burning natural gas for a significant portion of diesel fuel used in completion operations, which
during 2019 reduced the amount of diesel consumed by over 450,000 liters or approximately 25%, reducing GHG
emissions while reducing costs
ton
nes
CO
2e/b
oe
ESGGreenhouse Gas Emissions and Water Usage
Emissions Reduction
36
0.0087
0.0076
0.0064
0.0041
0.0033
0
0.002
0.004
0.006
0.008
0.01
2014 2015 2016 2017 2018
PONY is committed to
reducing Greenhouse Gas
(“GHG”) emissions through
deliberate actions which
produce measurable
improvements year after year
• 100% recycled water for completion operations in 2020, a significant milestone in PONY’s water conservation efforts
• PONY participates in a ‘Water Co-operative’ with other producers in the area to share completion water, reducing fresh water
use and water disposal costs
Water Conservation
CO2 Intensity
ESG Environmental, Social, Governance
• Institutional Shareholder Services Inc. (ISS) is the world’s leading provider of corporate governance
and responsible investment ratings. On a 1-10 scale where 1 is excellent and 10 is deficient, Painted
Pony received a quality score of ‘1’ in 2019, the highest score attainable and the highest in our peer
group of companies.
37
• Painted Pony has developed and implemented a complete portfolio of corporate policies including:
• Code of Ethics
• Corporate Disclosure
• Health, Safety and Environment
• Whistleblowing
• Respectful Workplace
• Compensation Clawback
• Insider Trading
• Director and Officer Share Ownership
• Painted Pony believes in diversity and this is reflected by the three women on the Board of Directors, with
two chairing Board committees
• Joan Dunne, Chair of Audit & Risk Committee
• Lynn Kis, Chair of Reserves & HSE Committee
• Betsy Spomer
• PONY’s board is 38% women, more than double the average for all TSX-listed companies of 16.4%*
ESG Environmental, Social, Governance
Governance
*Source: 2019 Diversity Disclosure Practices – published by Osler, Haskin & Harcourt
Well situated to supply Canadian west coast LNG projects
Diversified Market Access and Sales Points
Massive reserves base
Top well performance
Recent adjacent transaction shows significant upside value
Strong ESG Performance including Top Governance Score
PONY PointsChecking Off All of the Boxes
38
Appendices
&
Advisories
Financial Strength Term Debt and Credit Facility Provide Financial Flexibility
$350 Million Syndicated Credit Facility• Secured, Reserve Based Lending
• Matures May 2021
• $121 million drawn as at March 31, 2020
$145 Million Term Debt (Senior Unsecured Notes)
• Held by Magnetar Capital
• 8.5% Coupon
• $150 million maturity in 2022
• Not callable until August 2020
$48 Million Subordinated Convertible Debentures• Held by Magnetar Capital
• 6.5% Coupon
• $5.60 Conversion Price
• $50 million maturity 2021 (subject to any conversion)
• ‘No Shorting’ Provision included
Debt Capital
Diversification
Syndicated
Credit Facility
Drawn (as at March 31, 2020)
Undrawn (excluding Letters of Credit)
Senior Notes
Convertible Debentures
Drawn on Credit Facility
$229
$121
$121
$144
$47
40
Institution Analyst
AltaCorp Capital Patrick O’Rourke
BMO Capital Markets Michael Murphy / Ray Kwan
Canaccord Genuity Corp. Anthony Petrucci
CIBC World Markets David Popowich
Cormark Securities Inc. Garett Ursu
Desjardins Chris MacCulloch
Eight Capital Adam Gill
Stifel FirstEnergy Cody Kwong
Industrial Alliance Securities Michael Charlton
Raymond James Jeremy McCrea
RBC Capital Markets Michael Harvey
Scotiabank Global Banking & Markets Cameron Bean
TD Securities Juan Jarrah
Equity ResearchSell-Side Analyst Coverage
41
Auditor KPMG LLP
Evaluation Engineers GLJ Petroleum Consultants Ltd.
Banks
Transfer Agent
The Toronto-Dominion Bank
Canadian Imperial Bank of Commerce
The Bank of Nova Scotia
Alberta Treasury Branches
Royal Bank of Canada
HSBC Bank Canada
TSX Trust Company
Corporate Office
Suite 1200, 520 – 3rd Avenue SW
Calgary, Alberta T2P 0R3
Toll Free Investor 1 (866) 975-0440
Tel (403) 475-0440 Fax (403) 238-1487
Email: [email protected]
www.paintedpony.ca
Corporate Overview
42
This presentation contains a summary of management’s assessment of results and should be read in conjunction with the Financial Statements and related Management’s Discussion and Analysis for the year
ended December 31, 2019, as filed on SEDAR. This presentation contains certain forward-looking statements, which include assumptions with respect to (i) drilling success; (ii) commodity prices; (iii)
production; (iv) reserves; (v) future capital expenditures; (vi) future operating costs; (vii) availability of gas processing facilities; (viii) cash flow; (ix) potential markets for the Corporation’s production; (x) the
availability of LNG export facilities; (xi) global LNG demand; and (xii) natural gas consumption. The reader is cautioned that assumptions used in the preparation of such information may prove to be incorrect.
Certain information regarding the Corporation set forth in this presentation, including statements regarding management’s assessment of the Corporation’s future plans and operations, the planning and
development of certain prospects, production estimates, reserve estimates, productive capacity and economics of new wells, undeveloped land holdings and values, capital expenditures and the timing and
allocation thereof (including the number, location and costs of planned wells), facility expansion plans, the total future capital required to bring undeveloped proved and probable reserves onto production, and
expected production growth, may constitute forward-looking statements under applicable securities laws and necessarily involve substantial known and unknown risks and uncertainties. These forward-looking
statements are subject to numerous risks and uncertainties, certain of which are beyond the Corporation’s control, including without limitation, risks associated with oil and gas exploration, development,
exploitation, production, marketing and transportation, loss of markets, failure of foreign markets to become accessible, the impact of general economic conditions, industry conditions, volatility of commodity
prices, currency fluctuations, environmental risks, competition, the lack of availability of qualified personnel or management, inability to obtain drilling rigs or other services, capital expenditure costs,
including drilling, completion and facility costs, unexpected decline rates in wells, wells not performing as expected, stock market volatility, delays resulting from or inability to obtain required regulatory
approvals and ability to access sufficient capital from internal and external sources, the impact of general economic conditions in Canada, the United States and overseas, industry conditions, changes in laws
and regulations (including the adoption of new environmental laws and regulations) and changes in how they are interpreted and enforced, increased competition, fluctuations in foreign exchange or interest
rates and market valuations of companies with respect to announced transactions and the final valuations thereof. There is ongoing litigation involving the Blueberry River First Nation ("BRFN") and the British
Columbia government regarding the obligations of natural resource companies and the Crown relative to the adequacy of consultation and cumulative effects in respect of upstream oil and gas development in
northeast British Columbia, where a substantial portion of the Corporation’s land and assets are situated. The Corporation is not a party to the litigation. While a successful claim by BRFN may be adversely
material to the Corporation, at this point, the success of the claim and any corresponding impact is indeterminable. If the claim is decided in BRFN’s favour, it would have an adverse impact on the
Corporation, its operations and production, particularly for those operations that may be considered to impact Aboriginal traditional lands or rights. The Corporation is therefore, actively monitoring the status
of the BRFN claim. The Corporation’s actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no
assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits the Corporation will derive therefrom. All subsequent
forward-looking statements, whether written or oral, attributable to the Corporation or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. Additional
information on these and other factors that could affect the Corporation’s operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed
through the SEDAR website (www.sedar.com) or the Corporation’s website (www.paintedpony.ca), including the Corporation’s MD&A for the year ended December 31, 2019.
The forward-looking statements contained in this presentation are made as of the date on the front page and the Corporation assumes no obligation to update publicly or to revise any of the included forward-
looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws. Certain information contained herein is based on, or derived
from, information provided by independent third-party sources. The Corporation believes that such information is accurate and that the sources from which it has been obtained are reliable. The Corporation
cannot guarantee the accuracy of such information, however, and has not independently verified the assumptions on which such information is based. The Corporation does not assume any responsibility for
the accuracy or completeness of such information.
This presentation also contains future-oriented financial information and financial outlook information (collectively, "FOFI") about prospective results of operations, future net revenue, share capital, cash
flow, capital expenditures, net debt and components thereof, all of which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth in the above paragraphs. FOFI contained
in this presentation was made as of the date of this presentation and was provided for the purpose of providing information about management's current expectations and plans relating to the future, including
with respect to the Corporation’s ability to fund its expenditures. The Corporation disclaims any intention or obligation to update or revise any forward looking statements or FOFI contained in this
presentation, whether as a result of new information, future events or otherwise, unless required pursuant to applicable securities law. Readers are cautioned that the forward looking statements and FOFI
contained in this presentation should not be used for purposes other than for which it is disclosed herein. The forward looking statements and FOFI contained in this presentation are expressly qualified by this
cautionary statement.
Advisory
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Non-GAAP Measures: This presentation may make reference to the terms “adjusted funds flow from operations”, “adjusted funds flow from operations per share”, "corporate netback" and “net debt”, which do
not have standardized meanings prescribed by IFRS and therefore may not be comparable with the calculation of similar measures presented by other issuers. Management of the Corporation believes these
measures are useful supplemental measures of the net position of current assets and current liabilities of the Corporation and the profitability relative to commodity prices. Readers are cautioned, however, that
these measures should not be construed as alternatives to other terms such as current and long-term debt or comprehensive income determined in accordance with IFRS as measures of performance. The
Corporation's method of calculating these non-GAAP measures may differ from other companies, and accordingly, may not be comparable to similar measures used by other entities.
Management uses “adjusted funds flow from operations” to analyze operating performance and considers adjusted funds flow from operations to be a key measure as it demonstrates the Corporation’s ability to
generate the cash necessary to fund future capital investment and to repay debt. Adjusted funds flow denotes cash flow from operating activities before the effects of changes in non-cash working capital and
decommissioning expenditures. “Adjusted funds flow from operations per share” is calculated using the basic and diluted weighted average number of shares for the period. These terms should not be considered
alternatives to, or more meaningful than, cash flows from operating activities as determined in accordance with IFRS as an indicator of the Corporation’s performance.
Management uses “net debt” as useful supplemental measures of the liquidity of the Corporation. Net debt is calculated as bank debt, senior notes, liability portion of convertible debentures, and working capital
(deficiency), adjusted for the net current portion of fair value of risk management contracts and current portion of finance lease obligation. These terms should not be considered alternatives to, or more
meaningful than, current and long-term debt as determined in accordance with IFRS.
"Corporate netback" is used as a supplemental measure of the Corporation's profitability relative to commodity prices. Corporate netback is calculated on a per unit basis as natural gas and natural gas liquids
revenues, adjusted for realized gains or losses on risk management contracts, less royalties, operating expenses, transportation costs and finance lease expense. This term should not be considered alternatives to,
or more meaningful than net income (loss) and comprehensive income (loss) as determined in accordance with IRFS. Included in this presentation are estimates of the Corporation’s 2020 adjusted funds flow which
are based on various assumptions as to production levels, commodity prices and other assumptions, are provided for illustration only and are based on budgets and forecasts that have not been finalized and are
subject to a variety of contingencies including prior years’ results. To the extent such estimates constitute a financial outlook, they were approved by management of the Corporation in December 2018 and are
included to provide readers with an understanding of the Corporation’s anticipated adjusted funds flow based on the capital expenditures and other assumptions described. Readers are cautioned that the
information may not be appropriate for other purposes.
NOTE REGARDING RESERVES DISCLOSURE
The securities regulatory authorities in Canada have adopted National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”), which imposes oil and gas disclosure standards for
Canadian public issuers engaged in oil and gas activities. NI 51-101 permits oil and gas issuers, in their filings with Canadian securities regulatory authorities, to disclose proved, probable and possible reserves, and
to disclose reserves and production on a gross basis before deducting royalties. Probable and possible reserves are progressively less certain estimates than proved reserves.
All reserves information in this presentation are presented on a gross basis. Gross reserves are the total working interest reserves before the deduction of any royalties and including any royalty interests
receivable. Reserves estimates set forth herein with respect to the Corporation are based on the independent engineering evaluation of the Corporation’s oil, natural gas liquids and natural gas reserves (the “GLJ
Report”) prepared by GLJ Petroleum Consultants Ltd. (“GLJ”) effective December 31, 2019 and dated March 11, 2020. Before tax net present values set forth herein are based on a 10 percent discount rate and
GLJ’s January 1, 2020 forecast prices as applicable.
All estimates of future revenue in this presentation and in the documents incorporated herein by reference are, unless otherwise noted, after the deduction of royalties, development costs, production costs and
well abandonment costs but before deduction of future income tax expenses and before consideration of indirect costs such as administrative, overhead and other miscellaneous expenses. The estimated future
net revenues contained in this presentation and in the documents incorporated herein by reference do not represent the fair market value of the applicable reserves.
In this presentation:
a) the discounted and undiscounted net present value of future net revenues attributable to reserves do not represent the fair market value of reserves;
b) there is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserve estimates of natural gas and liquids reserves provided in this
presentation are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual natural gas and liquids reserves may be greater than or less than the estimates provided in this
presentation;
c) 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 the effects of
aggregation;
d) boe amounts may be misleading, particularly if used in isolation. Boe amounts have been calculated using the conversion ratio of six thousand cubic feet (6 Mcf) to one barrel of oil (1 bbl). A conversion ratio
of 6 Mcf to 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on
the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value; and
e) Mcfe amounts may be misleading, particularly if used in isolation. Mcfe amounts have been calculated by using the conversion ratio of 1 bbl to 6 Mcf. A conversion ratio of 1 bbl to 6 Mcfs based on an energy
equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as
compared to natural gas is significantly different from the energy equivalency of 1:6, utilizing a conversion on a 1:6 basis may be misleading as an indication of value.
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Advisory
Reserves are the estimated remaining quantities of conventional natural gas, shale gas and natural gas liquids anticipated to be recoverable from known accumulations, from a given date forward, based on: (i)
analysis of drilling, geological, geophysical and engineering data; (ii) the use of established technology; and (iii) specified economic conditions which are generally accepted as reasonable.
Reserves are classified according to the degree of certainty associated with the estimates.
a) Proved Reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved
reserves;
b) Probable Reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the
sum of the estimated proved plus probable reserves; and
c) Possible Reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the
estimated proved plus probable plus possible reserves.
Other criteria that must also be met for the categorization of reserves are provided in the Canadian Oil and Gas Evaluation (“COGE”) Handbook.
Each of the reserves categories (proved and probable) may be divided into developed and undeveloped categories.
a) Developed Reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when
compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing.
(i) Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently
producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainly.
(ii) Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of
production is unknown.
b) Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to
render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable) to which they are assigned.
In multi-well pools it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to subdivide the developed reserves for the pool between developed producing and
developed non-producing. This allocation should be based on the estimator’s assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their
respective development and production status.
Long Lateral Well List: :
The qualitative certainty levels referred to in the definitions above are applicable to individual reserves entities (which refers to the lowest level at which reserves calculations are performed) and to reported
reserves (which refers to the highest level sum of individual entity estimates for which reserve estimates are prepared). Reported reserves should target the following levels of certainty under a specific set of
economic conditions:
(a) at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves; and
(b) at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves.
A quantitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is desirable to provide a clearer understanding of the associated risks and uncertainties.
However, the majority of reserves estimates will be prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability. In principle, there should be no
difference between estimates prepared using probabilistic or deterministic methods. Additional clarification of certainty levels associated with reserves estimates and the effect of aggregation is provided in the
COGE Handbook.
For additional information regarding the presentation of the Corporation’s reserves and other oil and gas information, see the Corporation’s Form 51-101F1, which may be accessed through the SEDAR website
(www.sedar.com) or the Corporation’s website (www.paintedpony.ca).
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Advisory
