1. business and industrial
2. energy
3. natural gas

Canbriam Energy Inc.
April 2015
Key investment highlights
Prolific Montney
asset
Experienced
management with
strong sponsorship
Favorable
operating
environment
Large, low risk,
high return drilling
inventory
Integrated
development
strategy
2
Canbriam Energy: corporate overview
Overview

Private company started in 2007 and focused on
the prolific Montney formation in Northeast BC

March 2015 average production of ~18,000
boe/d (~20% liquids)

2014 production 9,628 boe/d (~20% liquids)


Asset map
North
Altares
Canbriam has a inventory of ~700 net liquidsrich locations and established a stable, low
decline production base
Significantly over-pressured reservoir in the
upper & lower Montney

281 MMboe gross 2P reserves (pre-tax PV10
of $2.4 billion)(1)

Backed by top-tier financial sponsors including
Warburg Pincus, ARC Financial, OTPP,
GE Asset Management, and BlackRock
b-24-H Refrig Facility
50 mmcf/d
b-72-A Refrig Facility
80 mmcf/d (phase 1)
Main
Fault
Block
Spectra
T North
Canbriam 100%
Dehy & compression
Facility 10 mmcf/d
2 miles
Canbriam Non-Montney Lands
65% - 70% Working Interest
South
Altares
(1) Based on McDaniel & Associates Consultants Ltd. (“McDaniel & Associates”) reserves report as of December 31, 2014.
33
Experienced Management team has a track record of value creation
Years
Paul Myers
President, CEO
25+
Robert Froese
Chief Financial Officer
25+
Gary Gardiner
Chief Operating Officer
30+
John Nieto
EVP, Sub-surface
35+
Donna Phillips
EVP, Corporate Development
25+
Larry Cole
VP, Finance
15
Art Flaws
VP, Drilling & Completions
30+
Nauman Rasheed
VP, Production & Facilities
15
Sean Brady
VP, Strategic Planning
15
Deep industry experience
4
Montney: significant well density & offset peer activity
Petronas/Progress -Town
30 km
Montney Wells
Canbriam Energy
Shell
Progress/Petronas
ARC
Encana
CNRL
Murphy
Suncor
Painted Pony
Black Swan
Unconventional Gas Resources
ARC - Dawson
Canbriam - Altares
Crew
Pengrowth
Brokers
Shell - Groundbirch
BC deep drilling royalty
credit boundary
Spectra T North Pipeline
ECA - Swan
5
Canbriam: unique geology within prolific Montney resource
4 key attributes of Canbriam’s Montney asset
1
Significant thickness

Could ultimately result in 3 or 4 commercial
development intervals
Total Montney thickness ~1,100 ft
2
High liquids content

2014 plant yield: 40 - 50 bbls/MMcf

~60% condensate;~20% propane; ~20% butane
7 Tested
zones
Liquids rich gas
Commercial
Interval1
Upper
C5
C4
Oil window
C3
Commercial
Interval 2
C2
Canbriam 100%
Canbriam Non-Montney Lands
Commercial
Interval 3
Piloting 4th
Interval
Lower
T1
65% - 70% Working Interest
Spectra
T North
T2
T3
Dry gas window
Source: Canbriam
Canbriam Montney - liquids mapping
6
Canbriam: unique geology within prolific Montney resource
4 key attributes of Canbriam’s Montney asset (cont’d)
3
Over-pressured reservoir

Results in higher OGIP & EUR

Significantly over-pressured in Main Fault Block

Downhole choke strategy enhances EUR,
improves well economics, sustains liquids yield,
and supports low declines
4
Sub-surface compartmentalization

Leads to distinct high-pressure regions with
consistent well results
North Fault Block
East Fault Block
Main Fault Block
South Fault Block
Overpressure
Normal pressure
Source: ITG, raw data from Geoscout
Note: 0.433 psi/foot = 10 KPa/meter
Canbriam Montney – pressure gradient mapping
Source: Canbriam
Canbriam Montney – fault compartmentalization mapping
7
Large drilling inventory supports low-risk production growth
Well inventory (net)
+34 years of upside
drilling inventory
~18 years of economic drilling inventory @ 36 wells / year
936
1622
186
686
318
107
686
40
35
Proved developed
Proved
undeveloped
Probable
Additional Upper Additional Lower
Montney
Montney
locations
locations
Total derisked
development
locations
Additional
locations
Total locations
Source: Company data and McDaniel & Associates reserves report as of 12/31/14.
8
Significant reserves growth with high liquids content
Upper vs. Lower booked locations
2P Reserve Growth
2P F&D costs & recycle ratio1
(MMboe)
55
Proved Lower , 21
Probable Upper, 25
Probable Lower, 15
226
23
Proved Upper, 121
20
15
7
1
8
21
2009
2010
42
2011
59
2012
Gas
87
2013
2014
Liquids
Summary of gross reserves as of Dec 31, 20142
Category
Natural Gas
(Bcf)
NGLs
(MMbbls)
Proved Developed
133.0
Proved Undeveloped
Total
PV10% ($MM)3
Net Locations
(MMBoe)
(%)
5.2
27.4
10%
$387
35
680.5
27.8
141.2
50%
$1,062
107
Total Proved
813.4
33.1
168.6
60%
$1,449
142
Probable4
544.7
21.5
112.3
40%
$965
40
1,358.1
54.6
280.9
100%
$2,414
182
Total Proved + Probable
Canbriam’s 2P bookings in 2014 reflect strong well performance and recognition of 2nd target within Upper Montney
(1)
(2)
(3)
(4)
Recycle ratio defined as operating netback divided by 2P Finding & Development costs.
Reserves are calculated on a gross company interest basis, before royalties and based on a 3 rig case through the current 5 year development plan.
Before tax and based on McDaniel & Associates pricing as of 1/1/15.
Probable reserves shown are for the 40 Probable Locations plus the Probable component of all the other 2P wells.
9
Stable production history with strong liquids content
120
Inlet Separator
b-24-H capacity
100
mmcf/d
Natural Gas
80
60
40
20
Sept-14: Plant turnaround
0
3,500
80
3,000
70
bbls/d
Liquids
50
2,000
40
1,500
30
1,000
Yield bbls/MMcf
60
2,500
20
500
10
Sept-14: Plant turnaround
0
0
Free Condensate
Condensate
Butane
Propane
Plant Yield (10 day average)
10
Development plan focused in the prolific Main Fault Block
Exploration wells: 11 wells since 2008
Development wells: 23 wells (March 31, 2015)
 Targeting 2 Upper & 1 Lower Montney zones within Main Fault Block

7 zones tested within Montney formation

Drilled within/across multiple geological faults
 Utilizing limited-entry, slickwater completions
 23 wells currently ~90% of total production (March 31, 2015)

Tested various completion techniques to high-grade
development

10 exploration wells currently ~10% of total production

17 Upper Montney (UM) – 14 Main Fault Block; 3 North Fault Block

6 Lower Montney (LM)
 Anticipate additional ~10 wells through 2015 based on current plan
Daily Raw Gas Production by Well – Upper & Lower Montney Development
Wells
Daily Raw Gas Production by Well - Exploration Wells
10,000
10,000
9 Bcf type curve (UM)
9,000
8 Bcf type curve (LM)
8,000
8,000
7,000
7,000
Daily Gas Rate (mcf/d)
Daily Gas Rate (Mcf/d)
9,000
6,000
5,000
4,000
3,000
6,000
5,000
4,000
3,000
2,000
2,000
1,000
1,000
0
0
0
100
200
300
400
500
600
Days on Production
700
800
900
1000
0
100
200
300
400
500
600
700
800
900
1000
Days on Production
Canbriam’s Main Fault Block is substantially de-risked and represents ~85% of the next 5 years development
11
Consistent well performance supports full scale development
Cumulative production by well – Main Fault Block (Upper) - First 1,000 days
5,000
4,500
4,000
b-A24-H
c-23-H
b-34-H
c-27-H
b-B24-H
c-B27-H
b-B74-A
b-C74-A
b-D74-A
9 bcf type curve
Cum Raw Gas (mmcf)
3,500
3,000
2,500
2,000
9 development wells
1,500
1,000
500
0
0
200
400
600
800
1000
Number of Days Flowing through Plant
Well performance has consistently tracked in line with the 9 Bcf raw gas type curve
12
Main Fault Block type well economic sensitivities
Montney NPV10 ($M) including hedge positions
Montney IRR including hedge positions
$18,000
100%
$16,000
90%
80%
$14,000
70%
$12,000
60%
$10,000
50%
$8,000
40%
$6,000
30%
$4,000
20%
$2,000
10%
$-
0%
Nymex $2.50
WTI $40.00
US/CAD FX 0.80
20% capital savings
Nymex $3.50
WTI $60.00
US/CAD FX 0.85
10% capital savings
Nymex $4.50
WTI $80.00
US/CAD FX 0.90
0% capital savings
Nymex $2.50
WTI $40.00
US/CAD FX 0.80
20% capital savings
Nymex $3.50
WTI $60.00
US/CAD FX 0.85
10% capital savings
Nymex $4.50
WTI $80.00
US/CAD FX 0.90
0% capital savings
Upper Montney
Lower Montney
Upper Montney IRR
Lower Montney IRR
Upper Montney (hedged)
Lower Montney (hedged)
Upper Montney (hedged)
Lower Montney (hedged)
Main Fault Block type wells demonstrate strong economic returns under different pricing scenarios
*Capital savings includes illustrative capital cost reductions from service providers such as drilling & completions. IRRs are calculated before tax.
13
Downhole chokes have improved decline rates
Advantages of using downhole chokes



Enhances EUR by maintaining bottom-hole
pressure
Prevents the formation of hydrates when
starting up wells
Protects surface pipe integrity through better
sand management
Higher separation between casing (15 MPa)
& line pressure (~3.0 MPa) demonstrates
strength of the well
15.0
30.0
14.0
28.0
13.0
26.0
12.0
24.0
11.0
22.0
Sept 2014: Post-turnaround
flush production
10.0
9.0
18.0
8.0
7.0
20.0
16.0
Jan 2014: upsized choke
incremental 1.47 MMcf/d
May 2014: upsized choke
incremental 2.38 MMcf/d
14.0
6.0
12.0
5.0
10.0
4.0
8.0
3.0
6.0
2.0
4.0
1.0
2.0
0.0
0.0
Shut-in casing pressure (MPa)

Manages 1st year production declines and
fosters stable production
Gas rate (MMcf/d)

Altares c-B27-H Well – Upper Montney
CTD: Dec 31, 2014 = 2.520 bcf
Canbriam’s use of downhole chokes optimizes its over-pressured reservoir
14
Infrastructure strategy supports large scale development
100% owned and operated Infrastructure

North Altares facilities
Processing facilities

b-24-H: 50 MMcf/d nameplate capacity online

b-72-A: scalable to 400 MMcf/d nameplate capacity

South Altares: 10 MMcf/d dehy & compression facility online

Existing gas sales line provides sufficient takeaway capacity

20-year permit to draw fresh water sufficient to meet future needs from Williston
Lake (operator & 75% ownership of water pipeline)

Source water pipeline extension & water hub facility scheduled start-up Q2 2015
Altares processing facility expansion
450
400
Potential future
expansion of
b-72-A to 400 MMcf/d
MMcf/d
350
300
250
200
Under
construction
b-72-A Train 1, phase 2: 80 MMcf/d
150
100
b-72-A Train 1, phase 1: 80 MMcf/d online Feb 2015
50
b-24-H: 50 MMcf/d current capacity
0
2013
2014
2015
2016
15
b-72-A facility: scalable design for efficient development
C-62-a Water hub
Commissioned March 2015
Train 2, phase 2: 120 MMcf/d
Sanctioning to be determined
Train 2, phase 1: 120 MMcf/d
Sanctioning decision in 2015
Train 1, phase 2: 80 MMcf/d
Q4 2015E commissioning
Train 1, phase 1: 80 MMcf/d
Commissioned in February 2015
October 2014
16
b-72-A facility: scalable design for efficient development
September 4, 2014
December 19, 2014
February 13, 2015 commissioned
17
Integrated water solution is a strategic advantage
Sourcing
Canbriam - Altares

20-year permit to access up to 10,000 m3/day of lowcost fresh water from Williston Lake

Permitted fresh water supports >1 Bcf/d production

Includes piping to service multiple frac operations
simultaneously
C-62-a
water treatment &
storage hub
Water treatment & recycle

Allows for continuous frac flow back while supplying
treated water to other frac operations

Eliminates water trucking in Main Fault Block
Phase 2
(pipeline extension
to water hub)
Disposal

Disposal well application submitted

Closed system eliminates trucking of disposal water
Cost
Status
Phase 1
$20 MM
complete
Phase 2
$18 MM
complete
C-62-a hub
$20 MM
complete
Disposal
~$7 MM
2016E
Phase 1
(source & pipeline)
Williston Lake
Canbriam’s integrated water strategy is expected to save $100 - $150 MM over the next five years
18
Operating environment supports development plan

Attractive fiscal regime in BC

Drilling credits & minimal retention drilling required
Spectra T North
Gas transmission
Mile post 73 NGL
terminal
Canbriam roads
NGLs

Supportive First Nations
Liquids
transportation

Accessible to service hub (Fort St. John)

Long-term access permit in place to major water
source (Williston Lake)

Next to major sales pipelines (Spectra T North)

Canbriam controls local roads; year round access
(some spring road bans)

Strong domestic demand & sufficient takeaway
capacity for liquids production
Fort St. John
Canbriam water
pipeline
Taylor
condensate
terminal
Williston Lake
Station 2 – Spectra
Canbriam enjoys a low royalty burden in BC, a positive working relationship with stakeholders and easy
access to operating infrastructure
19
Hedge positions & composition of total liquids production
Natural gas hedges (February 28, 2015)
Liquids hedges (February 28, 2015)
bbls/d
M Gj/d
90
80
70
60
50
40
30
20
10
0
$5.00
$3.16
$3.02
$4.00
$3.26
3,500
$120.00
$98.75
3,000
$97.35
2,500
$3.00
$2.00
$80.00
2,000
1,500
$40.00
1,000
$1.00
$0.00
2015
2016
500
0
$0.00
2015
2017
2016
Volume hedged
WTI weighted average price (C$/bbl)
Volume hedged
AECO weighted average price (C$/gj)
2014
Production
Production
Revenue
Pricing*
(%)
(%)
(% WTI)
Natural gas (MMcf/d)
46.9
81%
63%
-
Condensate (bbl/d)
1,102
11%
30%
90 - 95%
Butane (bbl/d)
359
4%
5%
45 - 50%
Propane (bbl/d)
356
4%
2%
15 - 20%
9,628
100%
100%
Total (boe/d)
*Ignores FX impact on realized pricing. Condensate include pentanes plus production.
20
Key investment highlights
Prolific Montney
asset
Large, low risk, high
return drilling
inventory
Integrated
development
strategy
Favorable operating
environment
Experienced
management with
strong sponsorship

Prolific EUR/well with ~1,100’ of Montney vertical thickness on ~61,000 (~50% liquids rich) net acres

168.6 mmboe of gross 1P Reserves (pre-tax PV10 of $1,449 million)(1)

280.9 mmboe of gross 2P Reserves (pre-tax PV10 of $2.414 million)(1)

100% working interest and operatorship in core lands

686 net locations in the Altares development area representing ~18 years of drilling inventory at a 4-rig pace

High reservoir pressure and use of down-hole chokes limits declines and facilitates rapid growth

Profitable in a ~US$2.50 NYMEX pricing environment

Extensive operating experience in the B.C. Montney

Canbriam’s success tied to early quality differentiation within Altares region

Processing facilities are 100% owned & operated; scalable infrastructure supports efficient development

Team approach fosters culture of collaboration, safety & high performance

Prudent approach to financial management supports solid financial position

100%-owned gathering and processing facilities under expansion to 130 mmcf/d capacity (~25,000 boe/d
with liquids) in Q1 2015 and 210 mmcf/d capacity (~40,000 boe/d with liquids) by year-end 2015

Long term access to water: 20 year permit to withdraw 10,000m 3 per day from Williston Lake

Low population density, favorable regulatory regime & proximity to gas sales pipeline

Year round access (activity reduced during 3 month spring thaw period)

Management team averages 25 years of industry experience with prominent E&P companies

Team was built specifically to be able to find and develop sweet spots within unconventional fairways

Experienced E&P sponsors including Warburg Pincus, ARC, OTPP, GE and BlackRock
(1) Based on McDaniel & Associates reserves report as of December 31, 2014.
21
Supplemental information
Canbriam’s integrated development strategy
Sub-surface & operations
Infrastructure
Management
• Canbriam’s success tied to
early quality differentiation
within Altares region
• Processing facilities are 100%
owned & operated
• Team approach fosters culture
of collaboration, safety & high
performance
• Approach to reservoir
characterization & evaluation
is a sustainable advantage
• Geology, Geophysics &
Reservoir engineering
integrated with Drilling &
Completions in real time
• High degree of control &
scalable design supports full
scale development
• Maintain, operate & patrol all
roads within Altares region
• Long-term approach to water
sourcing, handling & recycling
• Prudent approach to financial
management supports solid
financial position
• Proactive approach to First
Nations and all stakeholders
Canbriam has built the foundation for profitable, long-term development within the Montney
23
Strategies to enhance operational performance
1
Small footprint
3
Surface
Pad drilling minimizes surface
disturbance and lowers D&C
costs per well


Limited entry slickwater frac completions
Surface
Casing
(~250-500m)
Up to 18 well pads (5 wells per
GSU per target); many are
already built
Development focused on 3 most
commercial zones
Charlie
Lake
Halfway
Doig
Intermediate
Casing (7”
~1,650m)
Isolation
- Pumpdown flow
through
plugs
Perf
Clusters/Spacing
- 3-5 clusters
- 20-30 meter
spacing
Production Casing
(4.5” to TD)
Montney
Belloy
2
Limited entry slickwater frac completions increases operational efficiency

Perf design: # of clusters/cluster design, # of stages (15-24 typically), cluster
spacing (20-30m)

Sand concentration: 1.2-1.25 tonnes/meter (800-840 lbs/ft)

Water Volume: 800 – 1,200 m3/stage

Pump Rate/Pressure: 8-12m3/minute to maintain 55-60 mPa pressure
Managed pressure drilling
Reduced mud weight improves fluid flow rates and
results in higher rates of penetration
4
Well spacing
Tighter well spacing (~200M between well pairs) improves recovery factors

The wells on this pad are producing independently of each other
Porosity Property
A variation of
Permeability Property
Initial Reservoir
Pressure
24
Upper Montney wells have outperformed type curves
Type well assumptions
Canbriam development well vs. type curve
Main Fault Block (MFB) – Upper Montney
Drilling locations(1)
7,000
284
Well properties
Raw Gas Production Rate (Mscf/d)
6,000
Raw gas type curve (Bcf)(2)
9.0
Sales gas (Bcf)(3)
8.2
Liquids (Mbbl)(2)
367
EUR/well (total - Bcfe)
10.4
% liquids (of total EUR)(2)
21%
Liquids yield (bbls/MMcf)
41
5,000
4,000
9 Upper Montney wells - MFB
3,000
Well costs
2,000
1,000
D&C costs ($MM)
$10.2
Operating & transportation costs(4) ($/boe)
4.85
Average royalty rate(5)
17%
0
0
1
2
3
4
5
6
7
8
9
10
Cumulative Raw Gas (Bcf)
Budget 9 Bcf UM
(1)
(2)
(3)
(4)
(5)
Avg (9 UM Wells)
Expected undrilled Main Fault Block locations based on Canbriam subsurface model.
Type curve and liquid yields represents current planning basis for Canbriam.
Assumes shrinkage of 9%.
Operating costs includes all well costs and fixed plant costs. Transportation costs are ~$2.00/boe.
Crown royalty rate is 3% minimum until royalty credit of $2.4 MM per well is paid out, then up to 27% (natural gas) and 20% (liquids) thereafter. Royalty includes BC government cost allowance and
excludes average gross overriding royalty of 2.5% within the Main Fault Block.
25
Lower Montney well performance vs. type curves
Type well assumptions
Canbriam development well vs. type curve
Main Fault Block (MFB) – Lower Montney
7,000
Drilling locations(1)
149
Well properties
6,000
Raw Gas Production Rate (Mscf/d)
5,000
Raw gas type curve (Bcf)(2)
8.0
Sales gas (Bcf)(3)
7.3
Liquids (Mbbl)(2)
145
EUR/well (total - Bcfe)
8.1
% liquids (of total EUR)(2)
11%
Liquids yield (bbls/MMcf)
18
4,000
3 Lower Montney wells
3,000
Well costs
2,000
1,000
D&C costs ($MM)
$10.4
Operating & transportation costs(4) ($/boe)
5.20
Average royalty rate(5)
15%
0
0
1
2
3
4
5
6
7
8
9
10
Cum Raw Gas (Bcf)
Budget 8 Bcf LM
(1)
(2)
(3)
(4)
(5)
Ave (3 LM Wells)
Expected undrilled Main Fault Block locations based on Canbriam subsurface model.
Type curve and liquid yields represents current planning basis for Canbriam.
Assumes shrinkage of 9%.
Operating costs includes all well costs and fixed plant costs, but exclude any cost savings tied to commissioning of c-62-A water facility. Transportation costs are ~$1.50/boe.
Crown royalty rate is 3% minimum until royalty credit of $2.5 MM per well is paid out, then up to 27% (natural gas) and 20% (liquids) thereafter. Royalty includes BC government cost allowance and
excludes average gross overriding royalty of 2.5% within the Main Fault Block.
26
Robust historical netbacks ($/boe)
$35.88
$33.23
$0.88
$4.04
$1.37
$3.34
$26.94
$27.16
2012
2013
2014
$3.59
$90.76
$3.53
$72.48
$4.63
$76.90
$2.80
$2.26
$2.17
$3.67
$3.01
$2.96
$4.41
$4.27
$3.90
Realized price:
Cash royalties
$29.58
$0.70
$3.41
$1.97
$6.56
Operating expenses
$1.09
Transportation expenses
$21.23
Cash operating netback
(before hedging)
Realized prices
Natural gas ($/mcf)
NGLs ($/bbl)
Benchmark prices
Henry Hub (US$/mmbtu)
AECO ($/GJ)
Station 2 ($/GJ)
Strong netbacks result from liquids component & low cost structure
27
Supplemental reserves information
Reserves Reconciliation (1)
Proved
Probable
Proved + Probable
Natural Gas
NGLs
Total
Natural Gas
NGLs
Total
Natural Gas
NGLs
Total
Bcf
MMbbls
MMboe
Bcf
MMbbls
MMboe
Bcf
MMbbls
MMboe
217
10
46
302
13
64
519
23
110
Extensions &
Improved Recovery
339
14
71
380
15
78
719
29
149
Technical Revisions
274
9
55
(137)
(7)
(29)
137
3
26
Discoveries
-
-
-
-
-
-
-
-
-
Acquisitions
-
-
-
-
-
-
-
-
-
Dispositions
-
-
-
-
-
-
-
-
-
Economic Factors
-
-
-
-
-
-
-
-
-
(17)
(1)
(3)
0
0
0
(17)
(1)
(3)
813
33
169
545
22
112
1,358
55
281
December 31, 2013
Production
December 31, 2014
Summary of Future Development Costs(2)
December 31, 2013
Changes
December 31, 2014
(1)
(2)
Proved
Probable
Proved + Probable
Million
Million
Million
$367
$393
$759
$1,031
$154
$1,185
$1,397
$546
$1,944
Reserves are calculated on a gross company interest basis, before royalties and based on a 3 rig case through the current 5 year development plan
Undiscounted, as calculated by McDaniel & Associates as of 12/31/14 based on a 3 rig case through the current 5 year development plan
28
Upper Montney – Main Fault Block well data
Daily raw gas production by well – Upper Montney Main Fault Block development wells
10,000
b-A24-H
9,000
b-B24-H
8,000
c-23-H
7,000
Daily Gas Rate (mcf/d)
c-27-H
6,000
b-34-H
5,000
c-B27-H
4,000
9 Bcf type
curve
3,000
2,000
1,000
0
0
100
200
300
400
500
600
700
800
900
1000
Days on Production
Our near term development plan is focused primarily in the Main Fault Block
29
Forward-looking information
Certain statements included in this presentation constitute forward‐looking statements or forward‐looking information under securities legislation. Such
forward‐looking statements or information are provided for the purpose of providing information about management's current expectations and plans relating to the
future. Readers are cautioned that reliance on such information may not be appropriate for other purposes, such as making investment decisions. Forward‐looking
statements or information typically contain words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", "project" or similar words
suggesting future outcomes or statements regarding an outlook. Forward‐looking statements or information concerning Canbriam in this presentation may include,
but are not limited to, statements or information with respect to: future production levels and the expected timing for the achievement thereof; business strategy
and objectives; expected resource potential and future reserves; development and exploration plans and the timing and results thereof; the development of and
access to pipelines; the potential future development of LNG export facilities and Canbriam's ability to supply such projects.
Forward‐looking statements or information are based on a number of factors and assumptions which have been used to develop such statements and information
but which may prove to be incorrect. Canbriam believes that the expectations reflected in such forward‐looking statements or information are reasonable;
however, undue reliance should not be placed on forward‐looking statements because Canbriam can give no assurance that such expectations will prove to be
correct. In addition to other factors and assumptions which may be identified in this presentation, assumptions have been made regarding, among other things:
the impact of increasing competition; the timely receipt of any required regulatory approvals; the ability of Canbriam to obtain qualified staff, equipment and
services in a timely and cost efficient manner; the ability of Canbriam to obtain financing on acceptable terms; field production rates and decline rates; the ability to
replace and expand reserves through acquisition, development or exploration; the timing and costs of operating Canbriam’s business; the ability of Canbriam to
secure adequate product transportation, including access to pipelines and potential LNG export facilities; future oil and natural gas prices; currency, exchange and
interest rates; the regulatory framework regarding royalties, taxes and environmental matters; and the ability of Canbriam to successfully market its oil and natural
gas products. Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used.
Forward‐looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which
could cause actual results to differ materially from those anticipated by Canbriam and described in the forward‐looking statements or information. These risks and
uncertainties may cause actual results to differ materially from the forward‐looking statements or information. The material risk factors affecting Canbriam include,
without limitation, the accuracy of reserves and resources estimates; reliance on key personnel; general economic conditions; volatility in global market prices for
oil and natural gas; competition; liabilities and risks, including environmental liability and risks, inherent in oil and gas operations; the availability of capital;
alternatives to and changing demand for petroleum products; changes in legislation and the regulatory environment, including uncertainties with respect to
environmental legislation; title defects which may adversely affect Canbriam; the availability of drilling and related equipment in the particular areas where such
activities will be conducted; constraints related to product transportation; relationships with First Nations in areas in which Canbriam operates; Canbriam's
dependence on third parties; and other known or unknown factors.
The forward‐looking statements or information contained in this presentation are made as of the date hereof and Canbriam undertakes no obligation to update
publicly or revise any forward‐looking statements or information, whether as a result of new information, future events or otherwise unless required by applicable
securities laws. The forward‐looking statements or information contained in this presentation are expressly qualified by this cautionary statement.
30
RESOURCE. INNOVATION. COLLABORATION.
Canbriam Energy Inc.
3500, 450 1st Street SW
Calgary, AB Canada T2P 5H1
[email protected]
Tel: 403.269.2874
Fax: 403.269.7637
www.canbriam.com
Paul Myers
President & Chief Executive Officer
[email protected]
Rob Froese
Chief Financial Officer
[email protected]
Bill Stait
Director, Investor Relations
403.718.8564
[email protected]