Investor Update September 14, 2015 · 6 2.9 Tcfe Proved + Probable Reserves –Dec. 31, 2014(1) 68%...
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Investor Update December 2015
Transcript of Investor Update September 14, 2015 · 6 2.9 Tcfe Proved + Probable Reserves –Dec. 31, 2014(1) 68%...
Investor UpdateDecember 2015
2
Average Daily Production (1) 94.8 MMcfe/day (15,794 boe/d)
TSX Ticker Symbol PPY
Shares Outstanding (2) 100 million
Daily Trading Volume 1.7 million shares per day(30 day average )
Market Capitalization $337 million (10 day average closing price $3.37)
Net Debt (2) $64.9 million
Bank Credit Facilities (Two Year Term) $325 million($225 million currently, staged increases to $325 million by Oct. 31, 2016)
(1) Average Daily Production Volumes Nine Months Ended September 2015
(2) As at September 30, 2015
Corporate ProfileA Strong Intermediate Company
3
Asset FocusMontney
3
Successfully assembled, explored and de-risked a
massive resource play in Northeastern British Columbia
2.9 Tcfe (488 MMboe) Proved Plus Probable Reserves(1)
Moving into full production and funds flow growth phase
supported by PPY – AltaGas Strategic Alliance
Projecting production to exit Q4 2016 at over 240
MMcfe/d (40,000 boe/d)
Fully funded with funds flow from operations and 2-year
syndicated bank credit facilities
5-year plan based entirely on North American sales
Premium assets in the optimum area
Montney is one of the most prolific and economic natural
gas plays in North America
PPY wells have the highest average peak month rate of
all Montney operators in 2013 and 2014
West of BC Royalty Line (larger royalty credit per well)
Current and proposed sales pipelines intersect PPY
properties
Ideally suited & situated to be a future west coast LNG
supplier
(1) As at December 31, 2014; see Disclaimer Section
Reserves GrowthImpressive and Consistent
4
123
366
0.06 0.13 0.19
0.70
1.96
2.17
3.28
4.91
0
1
2
3
4
5
0
100
200
300
400
500
2007 2008 2009 2010 2011 2012 2013 2014
Reserv
es P
er
Basic
Share
(boe/s
hare
)
Re
se
rve
s (
MM
bo
e)
2P Reserves per Share
Proved
Probable
• 164% Compound Annual Growth in reserves, 2007 – 2014
• 88% Compound Annual Growth in reserves per share, 2007 – 2014
Canadian Natural Gas ReservesAs at Dec 31, 2014
5
2.6 Tcf
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
CNQ ECA TOU ARX PEY HSE PPY BIR VII AAV BNP POU CVE CR PGF IMO TLM CQE PMT KEL* TET ERF DEE
Can
ad
ian
Natu
ral G
as 2
P R
ese
rve
s (
Bcf)
2014 Cost of Supply
30% Increase in 2P Undeveloped Reserves per well
5.1x Recycle Ratio – FD&A (2P)
$1.48 2013 FDC/mcfe (1)
$1.13 2014 FDC/mcfe (1)
(1) FDC – Future Development Capital is capital necessary to develop those reserves deemed Undeveloped
Source: Company press releases and Annual Information Forms.
* KEL + RTK
24%
Reduction
6
2.9 Tcfe Proved + Probable Reserves – Dec. 31, 2014(1)
68% Increase in 2P Reserves in 2014
30% Increase in 2P Undeveloped Reserves per well in 2014
24% Decrease in 2P FDC per Mcfe in 2014 to $1.13 (4)
98 years Proved + Probable Reserve Life Index(2)
25 years Proved Reserve Life Index(2)
5.1 times 2014 Proved + Probable Recycle Ratio (FD&A)
3.1 times 2014 Proved Recycle Ratio (FD&A)
4,215% 2014 Production Replacement (Proved + Probable)
$2.6 billion NPV10 Proved + Probable Reserves – Dec. 31, 2014(1)
$2.9 billion Net Asset Value (NAV)(3)
$27.50 NAV Per Fully Diluted Share(3)
(1) See “Disclaimer” section.
(2) Based on fourth quarter 2014 annualized production
(3) NAV calculated using the NPV10 of 2P reserves as prepared by GLJ Petroleum Consultants effective December
31, 2014, plus undeveloped land evaluated by Seaton-Jordan & Associates Ltd., plus working capital as of
December 31, 2014. NAV Per Share calculated using shares outstanding as of December 31, 2014.
(4) FDC – Future Development Capital is capital necessary to develop those reserves deemed Undeveloped
ReservesSignificant Value
Production GrowthImpressive and Consistent
7
7611,553 2,849
4,220
6,589
8,693
13,192
15,500
23,000
23
44
61
71
93 98
145 145
156
230
0
50
100
150
200
250
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
45,000
50,000
2008 2009 2010 2011 2012 2013 2014 2015E 2016F
Annual A
vera
ge B
oe p
er
Day p
er
1 M
illio
n S
hare
s
Annual A
vera
ge D
aily
Pro
duction (
boe p
er
day)
• 145% Compound Annual Growth in production, 2007 – 2014
• 76% Compound Annual Growth in production per share, 2007 - 2014
Annual Average Daily Production per 1 Million Weighted-Average Shares
Oil & NGLs
Natural Gas
Q4 2016 Exit ProductionQ4 2016 Exit
40,000e Boe
per day
Well PerformanceTop Performing Wells Among Montney Producers
0
20
40
60
80
100
120
140
0
1
2
3
4
5
6
7
1 2 3 4 5 6 7 8 910 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44
Wel
l Co
un
t
20
13
-20
14
Ave
rage
Pea
k M
on
th R
ate
(M
Mcf
/d)
Operator Rank
Average 3.1 MMcf/d
Painted Pony
(6.2 MMcf/d)
Painted Pony Average Peak Month Rate Twice Average Comparable Wells
Source: geoSCOUT 8
275
Risk ManagementPrudent Downside Protection
AECO Financial Hedges
TermVolume (1)
(MMcf/d)
Price/Mcf
(CAD$)
% of Q3 2015
Production
2015 Q4 37.9 $3.14 43
2016 66.4 $3.03 75
2017 Q1 66.4 $3.03 75
2017 Q2 42.7 $3.06 48
2017 Q3-Q4 35.1 $3.15 40
2018 Q1-Q2 17.1 $3.18 19
2018 Q3 11.4 $3.18 13
2018 Q4 5.7 $3.11 6
9(1) Conversion of GJ to Mcf done at 1 Mcf = 1.055 GJ
• PPY natural gas averages a heating value of approximately 1,100 Btu
Fixed Differential Physical Contracts
2015
• 72% of estimated natural gas production in
November / December
• AECO minus fixed $0.64 / GJ
2016
• 37% of estimated natural gas production
January - October 2016
• AECO minus fixed $0.58 / GJ
The Montney TrendA Leading North American Gas Play
PPY’s Montney Sweet Spot is:
• a tight dolomitic siltstone with higher quality
reservoir than a shale
• 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
• in a 1.8x over-pressured area
• a high heat-content natural gas play with
value enhancing associated natural gas
liquids
• a commercially proven play with three distinct
layers currently producing with an additional
4 - 6 layers of potential under full exploitation
• positioned with excellent pipeline egress to
North American markets
10
300m
(984 ft)
Large contiguous land base with year-round
access
• 217 Net sections (139,049 net acres)
• 2nd Largest position in northern Montney west of
reduced royalty line
High working interest
• Average 75%, with operatorship on all key
properties
Attractive B.C. provincial royalty structure
• $2.2 million average royalty credit per well
• 3% royalty during royalty credit period
Highest avg. peak rate among Montney operators
• 80 wells drilled to-date (62 operated by PPY)
• ~198 locations in 5-year plan
High gas liquids (C3+) content
• Up to 60 bbls/MMcf forecast yield at Townsend
• 1,100 Btu/scf residual heat content
Land PositionPremium Assets in the Optimum Area
11
Northern
Montney
Development
Area
Southern
Montney
Development
Area
Capital Expenditures2015 and 2016
2015 Forecast
$107 million Anticipated capital investment
15.0 Total net drills
9.0 Total net completions
Other PPY Operated Pads
Blair
West
Blair
Cypress
Spectra Pipeline
Alaska Highway
Townsend
Daiber
Alliance
Pipeline5 miles>>
2016 Active Pads
12
Blair-
Townsend
Interconnect
Pipeline
2016 Budget
$215 million Anticipated capital investment
29.0 Total net drills
28.0 Total net completions
Sales Egress OptionalityFirm Transportation Supports Increasing Volumes
13
• Firm capacity on Spectra’s T-North
pipeline expands from approximately 46
MMcf/d currently to 266 MMcf/d in
November 2016
• Under terms of expanded firm capacity
agreement, PPY volumes can be sold at
either Station 2 or at Sunset Creek
• Expanded firm capacity:
• positions PPY for potential
AECO sales
• allows for longer-term delivery
contracts
• Expanded firm capacity
contracts will meet
approximately 84% of
anticipated 2017 fourth
quarter natural gas volumes
PPY Lands
Station
Processing Facility
Proposed Meter Station
Royalty Line
SPECTRA Pipelines
Alliance Pipelines
TCPL Pipelines
TCPL Proposed North
Montney Mainline Project
TechnologyParallel-Pair Completion
300-350 m
Inter-well
Spacing
~ 90-100 m Average
Fracture Stage Spacing
Ball-Drop
Packer
Surface Pad
Individual
Stage
Stimulation
Envelop
Region of
Completion
Enhancement
2015 Drilling
Activity are all
Parallel-Pairs
44-C (1)
41-F (1)
11-F (1)
26-L (1)
2-J (1)
6-F (Triple)
5-K (1)
Blair
Daiber
Townsend
West
Blair
14-F (1)
14
Improving Capital EfficienciesBlair-Daiber
15
0
1
2
3
4
5
6
7
8
9
10
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18
Pro
du
cin
g R
ate
(M
Mcfe
/d)
Production Month
72% increase in 6-month
cumulative production
(1.4 Bcfe vs. 0.8 Bcfe) All Perf & Plug (37 wells)
7.5 Bcfe Type Well
Single Well Ball-Drop (7 wells)
11 Bcfe Type Well
Parallel Pairs (8 wells)
15.5 Bcfe Type Well
Blair-Daiber Well Economics
NPV10* $3.0 million
IRR* 33%
Drilling $2.4 million
Completion $2.9 million
Equipping $0.6 Million
Total Well Cost $5.9 million
*Based on flat pricing using: $2.75 / Mcf NYMEX; $54 / Bbl $US WTI; $USD/$CAD FX $0.76
2016 Development Plan & EconomicsBlair – Daiber
• Expect to drill 12 net wells and complete 8 net wells in 2016
16
Development Program Economics
$5.9 million Drill, Complete, Equip & Tie-in
9.1 MMcfe/d IP30 Production Rate
15.5 Bcfe 2P Reserves per well
15 bbls/MMcf Liquids Recovery (C3+)
$3.0 million NPV per well @ 10% (BT)
33% IRR
2.6 years Payout Period (from spud)
$2.75 NYMEX (USD$/MMBtu)
$54.00 WTI (USD$/bbl)
$0.76 FX ($CDN/$USD)
Flat Pricing
Blair
West
Blair
Cypress
Spectra Pipeline
Alaska Highway
Townsend
Daiber
Alliance Pipeline5 miles>>
Nov. 5 2014 Purchase
Improving Capital EfficienciesTownsend
17
0
1
2
3
4
5
6
7
8
9
10
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18
Pro
du
cin
g R
ate
(M
Mcfe
/d)
Production Month
9.5 Bcfe Type Well
Perf & Plug (2 wells)
Townsend Well Economics
NPV10* $3.8 million
IRR* 40%
Drilling $2.4 million
Completion $2.9 million
Equipping $0.6 Million
Total Well Cost $5.9 million
Ball-Drop (8 wells)
113% increase in 6-month
cumulative production
(1.0 Bcfe vs. 0.5 Bcfe)
*Based on flat pricing using: $2.75 / Mcf NYMEX; $54 / Bbl $US WTI; $USD/$CAD FX $0.76
2016 Development Plan & EconomicsTownsend
• Expect to drill 17 net wells and complete 20 net wells in 2016
18
Blair
West
Blair
Cypress
Spectra Pipeline
Alaska Highway
Townsend
Daiber
Alliance Pipeline5 miles>>
Nov. 5 2014 Purchase
Development Program Economics
$5.9 million Drill, Complete, Equip & Tie-in
7.4 MMcfe/d IP30 Production Rate
9.5 Bcfe 2P Reserves per well
60 bbls/MMcf Liquids Recovery (C3+)
$3.8 million NPV per well @ 10% (BT)
40% IRR
2.2 years Payout Period (from spud)
$2.75 NYMEX (USD$/MMBtu)
$54.00 WTI (USD$/bbl)
$0.76 FX ($CDN/$USD)
Flat Pricing
Development EconomicsFlat Price Sensitivity
19
Townsend(9.5 Bcfe Single Well
Ball-Drop Type Well)
Based on flat pricing using: $54 $US WTI; $USD/$CAD FX $0.76
Blair-Daiber(15.5 Bcfe Paired
Parallel Type Well)
0%
10%
20%
30%
40%
50%
60%
70%
$2.25 $2.50 $2.75 $3.00 $3.25
IRR
Flat NYMEX, $USD/mmbtu
16
15,500 23,000 48,000 Daily Production (boe/d
93 138 288 Daily Production (MMcfe/d)
900 2,300 5,300 NGL Production (bbls/d)
15 29 44 Net Wells Drilled
-
10,000
20,000
30,000
40,000
50,000
60,000
Jan
-15
Ju
l-15
Jan
-16
Ju
l-16
Jan
-17
Ju
l-17
Jan
-18
Ju
l-18
Jan
-19
Pro
du
ctio
n, b
oe
pe
r d
ay
2019
2017
2016
2015
Base
2017
20
3-Year Development ModelImproved Well Performance Drives Down Well Count
1st AltaGas
Townsend Facility
(150 MMcf/d)
1st AltaGas
Townsend Facility
(48 MMcf/d)
350
300
250
200
150
100
50
Cu
mu
lative
we
ll co
un
t
Improved well performance
has reduced the number of
wells necessary to meet
production targets from 105
net wells to 88 net wells
105 net wells2015 3-Year Model
88 net wells2016 3-Year Model
16%
Development ModelCash Flow Growth
21
$75
$186
$246
$352
$87
$216
$331
$502
$-
$100
$200
$300
$400
$500
$600
$700
2016 2017 2018 2019
$287 (previous)
$215
(confirmed)
$350
(new)
$505
(new)$435 (previous)
$647 (previous)
-22%
Reduction
-29%
Reduction
Funds Flow
Positive
Revised Anticipated Annual Capital Budget
Previous Anticipated Annual Capital Budget
Previous model based on flat pricing using: $2.75 $US/mmbtu NYMEX; $59 $US WTI; $USD/$CAD FX $0.80
-25%
Reduction
-20%
Reduction
Annual Forecast Funds Flow per Previous Development Model
Annual Forecast Funds Flow per Updated Development Model
Updated model based on flat pricing using: $2.75 $US/mmbtu NYMEX; $54 $US WTI; $USD/$CAD FX $0.76
$371
(new)
$523 (previous)Total capital reduction of
$0.5 billion while maintaining
production growth profile
Previous $1.9 billion
NEW $1.4 billion
Per accounting standards, the capital lease expense for the AltaGas Townsend Facility is expected to be: $9.7mm in 2016; $38.0mm in 2017; $45.8mm in 2018; $69.5mm in 2019 and is not
reflected in funds flow from operations
Annual Debt to Funds FlowImproved Well Performance Driving Lower Leverage
22
1.9x
2.4x
3.8x
3.2x
1.3x
1.5x
1.9x
1.1x
0
1
2
3
4
2016 2017 2018 2019
Previous Forecast New Forecast
-50%
-66%
Improved well performance
is driving stronger capital
efficiencies, resulting in
less forecasted leverage
and a compression of
forecast year-end debt to
funds flow ratios
-32%
-38%
New Forecast based on flat pricing using: $2.75 $US/mmbtu NYMEX; $54 $US WTI; $USD/$CAD FX $0.76
Previous Forecast based on flat pricing using: $2.75 $US/mmbtu NYMEX; $59 $US WTI; $USD/$CAD FX $0.80
Ne
t D
eb
t to
Fu
nd
s F
low
Ra
tio
Year-end net debt to fourth quarter annualized funds flow
Per accounting standards, the capital lease expense for the AltaGas Townsend Facility is expected to be: $9.7mm in 2016; $38.0mm in 2017; $45.8mm in 2018; $69.5mm in 2019 and is not
reflected in funds flow from operations
Prudent LeverageBalance Sheet Strength Maintained
23
3.0x 3.2x
2.6x
1.3x1.6x 1.8x 1.6x 1.5x
-
1.0
2.0
3.0
4.0
Q1 2016 Q2 2016 Q3 2016 Q4 2016 Q1 2017 Q2 2017 Q3 2017 Q4 2017
$2.75 NYMEX Pricing
3.5x3.8x
3.1x
1.7x2.0x
2.4x 2.3x 2.2x
0.0
1.0
2.0
3.0
4.0
Q1 2016 Q2 2016 Q3 2016 Q4 2016 Q1 2017 Q2 2017 Q3 2017 Q4 2017
$2.25 NYMEX Pricing
2.6x 2.8x
2.2x
1.0x 1.3x 1.3x 1.2x 1.0x
0.0
1.0
2.0
3.0
4.0
Q1 2016 Q2 2016 Q3 2016 Q4 2016 Q1 2017 Q2 2017 Q3 2017 Q4 2017
$3.25 NYMEX Pricing
Townsend Facility Begins
Operations 150 MMcf/d
Based on flat pricing using: $54 $US WTI; $USD/$CAD FX $0.76 / quarter-end net debt to annualized quarterly funds flow
Townsend Facility
Increase 48 MMcf/d
Per accounting standards, the capital lease expense for the AltaGas Townsend Facility is expected to be: $9.7mm in 2016; $38.0mm in 2017; $45.8mm in 2018; $69.5mm in 2019 and is not reflected
in funds flow from operations
AltaGas Strategic AllianceDeal with People You Trust
AltaGas is PPY’s Primary Natural
Gas and NGL Marketer
Liquids-Rich Natural Gas Processing• Provides for the development of essential liquids-rich gas
processing facilities
Market-Competitive Product Pricing• AltaGas commits to seeking transactions at sales prices
greater than comparable area third party marketers
PPY Becomes AltaGas’ Primary Export Supplier• PPY receives preferred access to delivering gas on
export contracts which flow through AltaGas operated
facilities
Flexibility to Develop and Process Lean Gas• Allows PPY to independently build lean gas processing
facility anywhere on our land base
24
Potential LNG
Export Opportunity
from Kitimat
via PNG Pipeline
Existing
AltaGas PNG
Mainline 10”
Planned access
to both B.C. and
Alberta Natural
Gas Sales
Systems
Potential
NGL + LPG Export
Opportunity
from Washington via
ALA-PetroGas
at Ferndale
FacilitiesKey Infrastructure
Blair
Cypress
Townsend
Daiber
PPY Montney Lands
New AltaGas Townsend Facility:
• Major new shallow-cut facility
• 198 MMcf/d gross capacity
• PPY has secured firm capacity for entire plant
• Expected completion in mid-2016
Additional Townsend Area Facilities
• Potential for additional facilities which could
be built on same site planned for 2018
25
AltaGas Townsend
Facility under
construction
adjacent to PPY’s
existing 25 MMcf/d
Townsend plant
Blair-Townsend
Gas Gathering
Interconnect
Existing AltaGas
Blair Creek Plant (80mmcf/d)
West Blair (25 mmcf/d)
Alaska Highway
Daiber(50 mmcf/d)
AltaGas Construction UnderwayOn Time, On Budget
26
Inlet Package 1 – on site Inlet Package 2 - building under construction
Blair – Townsend Pipeline
90% complete
Proposed West Coast LNGA Long Call Option for PPY Gas
Key Advantages for Canadian LNG:
• Short sailing times to Japan and northern Asia
• Average ambient temperature (6 Celsius) reduces
liquefaction energy costs
• Canada’s well-established oilfield service industry
provides cost insulation
Selected Canadian
LNG Projects Export Capacity
Shell LNG CanadaIn-service 2019
~3.2 Bcf/d
Petronas Pacific NW LNGIn-Service 2019
~2.9 Bcf/d
AltaGas-Idemitsu Douglas
Channel LNGIn-Service 2018
~0.1 Bcf/d
27
PNG
Mainline
10”
Chevron
Approved
Pipeline
42”
Proposed
Spectra
BG Group
Proposed
TransCanada
Petronas
Spectra
Mainline
36”and 30”
Proposed
TransCanada
Shell
42”
The Best Pony in the Race
Premier Montney Asset Base• Large, contiguous land position with year-round access, located 100% in B.C.
• Geological, infrastructure and royalty sweet spot
• High-rate, liquids-rich, sweet natural gas wells
Proven low-cost Montney operator• Excellent economics at domestic gas prices
• Significant value uplift from increased liquids recovery
• Top decile 2014 FD&A recycle ratios of 5.1x (2P), 3.1x (1P) and 2.3x (PDP)
• 2014 2P FD&A cost of $0.70/Mcfe
Ideally situated and timed for LNG projects• On existing and proposed pipeline routes to Canada and U.S. west coasts
• Optimum heat content for LNG export - 1,100 Btu/scf
• Substantially de-risked – Aggressive production and funds flow growth phase has commenced
• Line-of-sight to increased net processing capacity of 198 MMcf/d in approximately nine months
28
Appendices & Disclosures
29
16
15,500 23,000 48,000 72,000 102,000 Daily Production (boe/d
93 138 288 432 612 Daily Production (Mmcfe/d)
900 2,300 5,300 7,800 12,000 NGL Production (bbls/d)
15 29 44 69 41 Net Wells Drilled
-
100
200
300
400
500
600
700
-
20,000
40,000
60,000
80,000
100,000
120,000
Jan
-15
Ju
l-15
Jan
-16
Ju
l-16
Jan
-17
Ju
l-17
Jan
-18
Ju
l-18
Jan
-19
Ju
l-19
Pro
du
cti
on
, B
OE
/d
2019
2018
2017
2016
2015
Base
318 net wells2014 5-Year Model
249 net wells2015 5-Year Model
198 net wells2016 5-Year Model
30
5-Year Development ModelImproved Well Performance Drives Down Well Count
The number of
wells necessary to
achieve annual
production volume
targets has
decreased by 38%
due to improved
well performance
and design
38%1st AltaGas
Townsend Facility
(150 MMcf/d)
1st AltaGas
Townsend Facility
(48 MMcf/d)
2nd AltaGas
Townsend Facility
(150 MMcf/d)
2nd AltaGas
Townsend Facility
(48 MMcf/d)
Production GrowthImpressive and Consistent
31
Annual Average Daily Production per 1 Million Weighted-Average Shares
Oil & NGLs
Natural Gas
2,849 4,220 6,589 8,69313,192 15,500
23,000
48,000
72,000
102,000
61 71 93 98
145 156
230
475
699
962
0
100
200
300
400
500
600
700
800
900
1,000
0
20,000
40,000
60,000
80,000
100,000
2010 2011 2012 2013 2014 2015E 2016F 2017F 2018F 2019F
Boe p
er
day p
er
Mill
ion S
hare
s
Pro
duction,
avera
ge a
nnual daily
boe p
er
day
• 48% Compound Annual Growth in
production, 2010–2014
• 26% Compound Annual Growth in
production per share, 2010 – 2014
• 57% Compound Annual Growth in
estimated production growth per share
Proposed West Coast LNG Projects
32
Proposed LNG Projects Capacity
Exxon – ImperialWCC LNG
~4.0 Bcf/d
Shell – Petrochina, Mitsubishi, KOGASLNG Canada
~3.2 Bcf/d
Nexen / CNOOC – Inpex, JGCAurora Liquefied Natural Gas Ltd.
~3.1 Bcf/d
BG GroupPrince Rupert LNG
~2.9 Bcf/d
Petronas – JapexPacific Northwest LNG
~2.6 Bcf/d
Kitsault Energy Ltd.Kitsault Energy Ltd. (Private)
~2.6 Bcf/d
Veresen IncJordan Cove LNG
~1.4 Bcf/d
Chevron – ApacheKM LNG
~1.3 Bcf/d
AltaGas – IdemitsuTriton LNG
~0.3 Bcf/d
Pacific Oil & GasWoodfibre LNG
~0.3 Bcf/d
Total Filed Application Capacity (NEB) ~21.7 Bcf/d
PNG
Mainline
10”
Chevron
Approved
Pipeline
42”
Proposed
Spectra
BG Group
Proposed
TransCanada
Petronas
Spectra
Mainline
36”and 30”
Proposed
TransCanada
Shell
42”
AltaGas Strategic Alliance
• Calgary-headquartered, Canadian natural gas mid-streamer
• Currently processing more than 2 Bcf/d natural gas and 70,000 bbls/d NGL
• Owns over 1,100 km of gas and NGL transmission pipelines
• Marketing natural gas in Alberta for 20 years and B.C. for 10 years
• Owns the only existing natural gas sales pipeline line to Canada’s West
Coast: Pacific Northern Gas (PNG)
• 1/3 Owner of PetroGas (NGL marketing and logistics), with the only LPG
export terminal on the west coast of North America at Ferndale, Washington
• Established partnership with Idemitsu Corp., Japan’s 2nd largest petroleum
refiner,to pursue Canadian gas (LNG, NGL, LPG) export initiatives
AltaGas Corporate Profile
33
Equity ResearchAnalyst Coverage
Institution Analyst
AltaCorp Capital Patrick O’Rourke
Canaccord Genuity Corp. Anthony Petrucci
CIBC World Markets Adam Gill
Cormark Securities Inc. Garett Ursu
Credit Suisse Securities David Phung
Desjardins Capital Markets Jamie Kubik
FirstEnergy Capital Cody Kwong
GMP Securities Aaron Swanson
National Bank Financial Dan Payne
Paradigm Capital Inc. Ken Lin
RBC Capital Markets Michael Harvey
Scotiabank Global Banking & Markets Cameron Bean
TD Securities Juan Jarrah
34
Corporate Overview
Auditor KPMG LLP
Evaluation Engineers GLJ Petroleum Consultants Ltd.
Banks The Toronto-Dominion Bank
The Bank of Nova Scotia
Alberta Treasury Branches
Canadian Imperial Bank of Commerce
HSBC Bank Canada
Wells Fargo Bank
Corporate Office
1800, 736 – 6th Avenue SW, Calgary, AB T2P 3T7
Toll Free Investor 1 (866) 975-0440
Tel (403) 475-0440 Fax (403) 238-1487
Email: [email protected]
www.paintedpony.ca
35
Endnotes
R: Reserves per share are calculated by dividing P+P reserves by shares outstanding at the end of the year. As at December 31, 2014, Painted
Pony’s P+P reserves were 488.4 MMboe and there were 99.5 million shares outstanding. Also see “Note Regarding Reserves Disclosure” in
“Disclaimer” section.
P: Production per million shares is calculated by dividing average production in the time period by the basic weighted average shares for the same
time period. 2014 production averaged 13,192 boe/d and Painted Pony had 91.2 million weighted average shares during 2014. Amounts and
estimates beyond 2014 are those of Painted Pony’s management as of the date hereof. Also see “Disclaimer” section.
IRR: The internal rate of return on an investment or project is the “annualized effective compounded return rate” that makes the net present value of all
cash flows from a particular investment or project equal to zero.
IRR, NPV and Payout Period are all pre-tax
36
Advisory
This presentation contains a summary of management’s assessment of results and should be read in conjunction with the Consolidated Financial Statements and related Management’s Discussion and Analysis for the quarter
ended September 30, 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 Company’s production; and (x) the availability of LNG export facilities. The reader
is cautioned that assumptions used in the preparation of such information may prove to be incorrect.
Certain information regarding the Company set forth in this presentation, including statements regarding management’s assessment of the Company’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 Company’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. Readers are cautioned that the foregoing list of factors is not
exhaustive. The Company’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 Company will derive therefrom. All subsequent forward-looking statements, whether written or oral,
attributable to the Company 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 Company’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 Company’s website (www.paintedpony.ca),
including the Company’s MD&A for the quarter ended September 30, 2015.
The forward-looking statements contained in this presentation are made as of the date on the front page and the Company 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 Company believes that such information is accurate and that the sources from which it has been obtained are reliable. The Company cannot guarantee the accuracy of such information,
however, and has not independently verified the assumptions on which such information is based. The Company 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 Company’s ability to fund its
expenditures. The Company 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.
NON-GAAP MEASURES
This presentation contains references to measures used in the oil and gas industry such as “cash flow” and “net debt’” These measures do not have any standardized meanings within International Financial Reporting
Standards (“IFRS”) and, therefore, reported amounts may not be comparable to similarly titled measures reported by other companies. These measures have been described and presented in this presentation in order to
provide shareholders and potential investors with additional information regarding Painted Pony’s liquidity and its ability to generate funds to finance its operations. Cash flow should not be considered an alternative to, or more
meaningful than, cash provided by operating, investing and financing activities or net earnings as determined in accordance with IFRS, as an indicator of Painted Pony’s performance or liquidity. Cash flow is used by Painted
Pony to evaluate operating results and the Company’s ability to fund capital expenditures and repay debt. Painted Pony uses net debt as a measure to assess its financial position. Net debt includes current liabilities, including
Painted Pony’s credit facility, less current assets excluding risk management contracts.
Included in this presentation are estimates of the Company's 2015-2019 cash 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 Company in November 2015 and are included to provide readers with an understanding of the Company's anticipated cash flow based on the capital expenditures and other assumptions described and
readers are cautioned that the information may not be appropriate for other purposes.
37
Advisory
NOTE REGARDING RESERVES DISCLOSURE
The reserves and resources estimates contained herein, including the corresponding estimates of future net revenue, are estimates only and the actual results may be greater than or less than the estimates provided
herein. There is no certainty that it will be commercially viable to produce any portion of the resources.
"Contingent Resources" is defined in the Canadian Oil and Gas Evaluation Handbook as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using
established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic,
legal, environmental, political, and regulatory matters, or a lack of markets. It is also appropriate to classify as Contingent Resources the estimated discovered recoverable quantities associated with a project in the early
evaluation stage. Contingent Resources are further classified in accordance with the level of certainty associated with the estimates and may be subclassified based on project maturity and/or characterized by their
economic status.
"Prospective Resources" are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources
have both an associated chance of discovery and a chance of development. Prospective Resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their
discovery and development and may be subclassified based on project maturity.
"Reserves" are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological,
geophysical, and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Reserves are further classified according to the level of certainty
associated with the estimates and may be subclassified based on development and production status.
"Total Petroleum Initially-In-Place" or "TPIIP" is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to
be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered (equivalent to “total resources”).
The most significant positive and negative factors with respect to the resource estimates relate to the fact that the field is currently at an evaluation/delineation stage. The Montney formation is aerially extensive in this
region, however well control is limited. Both resources-in-place and productivity may be higher or lower than current estimates.
Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 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 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 Mcf: 1 bbl, utilizing a conversion ratio at 6 Mcf:
1 bbl may be misleading as an indication of value. Mcfe may be misleading, particularly if used in isolation. A Mcfe conversion ratio of 1 bbl: 6 Mcf 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 the value ratio based on the current price of natural gas as compared to crude oil is significantly different from the energy equivalency of
1 bbl: 6 Mcf, utilizing a conversion ratio at 1 bbl: 6 Mcf may be misleading as an indication of value.
The estimated values of future net revenue disclosed in this presentation, whether calculated with or without a discount rate, 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 the effects of aggregation. Estimates of reserves for individual properties may not
reflect the same confidence level as estimates of reserves for all properties due to the effects of aggregation.
Painted Pony’s total working interest reserves, Contingent Resources and Prospective Resources are before royalties owned by others. The estimated future net revenues are stated before deducting income taxes and
future estimated site restoration costs, and are reduced for estimated future abandonment costs and estimated capital for future development associated with the contingent resources. It should not be assumed that the
undiscounted and discounted net present values represent the fair market value of the contingent resources and Prospective Resources.
In this presentation, information has been provided with respect to certain production information for lands and wells which is "analogous information" as defined applicable securities laws. This analogous information is
derived from publicly available information sources which Painted Pony believes are predominantly independent in nature. Some of this data may not have been prepared by qualified reserves evaluators or auditors and the
preparation of any estimates may not be in strict accordance with the Canadian Oil & Gas Evaluation Handbook. Regardless, estimates by engineering and geo-technical practitioners may vary and the differences may be
significant. Painted Pony believes that the provision of this analogous information is relevant to Painted Pony's activities, given its acreage position and operations (either ongoing or planned) in the area in question,
however, readers are cautioned that there is no certainty that any of the development on Painted Pony's properties will be successful to the extent in which operations on the lands in which the analogous historical
production information is derived from were successful, or at all.
The well test results disclosed in this presentation represent short-term results, which may not necessarily be indicative of long-term well performance or ultimate hydrocarbon recovery therefrom. In this presentation,
“working interest” reserves are calculated as the Company’s share of reserves, excluding royalty interest reserves and before the deduction of royalty burdens payable. The reserves report was prepared utilizing definitions
as set out under National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities.
38
