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

Canbriam Energy Inc.
February 2015
Canbriam Energy: corporate overview
Overview

Private company started in 2007 and
focused on the prolific Montney formation in
Northeast BC

2014E production ~10,000 boe/d (20%
liquids)

Canbriam has de-risked an inventory of
~700 highly economic net locations and
established a stable, low decline production
base

Significantly over-pressured reservoir in the
upper & lower Montney

110 MMboe gross 2P reserves (pre-tax
PV10 of $1.1 billion)(1)

Backed by top-tier financial sponsors
including Warburg Pincus, ARC Financial,
OTPP, GE Asset Management, and
BlackRock
Asset map
North
Altares
b-24-H Refrig Facility
50 mmcf/d
Main
Fault
Block
b-72-A Refrig Facility
80 mmcf/d (Q1 2015)
Spectra T
North
South
Altares
Canbriam 100%
Canbriam Non-Montney Lands
2 miles
Dehy &
compression
Facility 10
mmcf/d
65% - 70% Working Interest
(1) Based on GLJ reserve report dated December 31, 2013.
22
Experienced Management team has a track record of value creation
Years
Paul Myers
President, CEO
25+
Robert Froese
CFO
25+
John Nieto
EVP, Sub-surface
35+
Gary Gardiner
EVP, Operations
30+
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
3
Montney: significant well density & offset peer activity
Petronas/Progress -Town
Montney Wells
12 miles
Canbriam
Shell
Progress/Petronas
ARC
Encana
CNRL
Murphy
Suncor
Painted Pony
Black Swan
Unconventional Gas Resources
Crew
Arc - Dawson
Brokers
Canbriam - Altares
Shell - Groundbirch
ECA - Swan
4
Canbriam: unique geology within prolific Montney resource
4 key attributes of Canbriam’s Montney asset
1
Significant thickness

2
Could ultimately result in 3 or 4 resource play
developments
Total Montney thickness ~1,100 ft
7 Tested
zones
High liquids content

2014 YTD plant yield 40 - 50 bbls/MMcf

~60% condensate

~20% propane; ~20% butane
Upper
C5
Zone 1
C4
Liquids rich gas
C3
Zone 2
Oil window
C2
Total Eagleford thickness ~180 ft
Zone 3
Lower
T1
T2
Total Marcellus thickness ~150 ft
T3
Dry gas window
Source: Canbriam
Canbriam Montney - liquids mapping
= 3 development zones
5
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
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
6
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
198
686
395
25
Proved developed
28
Proved undeveloped
686
40
Probable
Additional Upper
Montney locations
Additional Lower
Montney locations
Total derisked
Additional locations
development locations
Total locations
Source: Company data and GLJ reserve report as of 12/31/13.
7
Stable production history with strong liquids content
LTM Production
60
50
mmcf/d
Gas
40
Inlet Separator
b-24-H capacity
30
20
10
Sept-14: Plant turnaround
0
Aug-13
Sep-13
Oct-13
Nov-13
Dec-13
Jan-14
Feb-14
Mar-14
Apr-14
May-14
Jun-14
Jul-14
Aug-14
Sep-14
2,500
60
.
bbls/d
Liquids
40
1,500
30
1,000
20
500
Yield bbls/MMcf
50
2,000
10
Sept-14: Plant turnaround
0
Aug-13
0
Sep-13
Oct-13
Nov-13
Free Condensate
Dec-13
Jan-14
Condensate
Feb-14
Mar-14
Butane
Apr-14
May-14
Propane
Jun-14
Jul-14
Aug-14
Sep-14
Plant Yield (10 day average)
8
Development plan focused in the prolific Main Fault Block
Exploration wells: 11 wells since 2008
Development wells: 13 wells (Sept 30, 2014)
 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
 13 wells currently ~80% of total production (Sept 30, 2014)

Tested various completion techniques

11 Upper Montney (UM) – 8 Main Fault Block; 3 North Fault Block

Multiple ‘lessons learned’ to high-grade development

2 Lower Montney (LM)

10 exploration wells currently ~20% of total production
 Anticipate additional ~16 wells on stream through mid-year 2015
Daily Raw Gas Production by Well – Upper & Lower Montney Development Wells
10,000
9,000
9,000
8,000
8,000
9 Bcf type curve
Daily Gas Rate (mcf/d)
Daily Gas Rate (Mcf/d)
Daily Raw Gas Production by Well - Exploration Wells
10,000
7,000
6,000
5,000
4,000
3,000
8 Bcf type curve
7,000
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
9
Illustrative well economics - Upper Montney
Illustrative well economics
Canbriam development well vs. type curve
Main Fault Block (MFB) – Upper Montney
Drilling locations(1)
7,000
284
Well properties
Raw Gas Production (Mscf/d)
6,000
5,000
Raw gas type curve (Bcf)(2)
9.0
Sales gas (Bcf)(3)
8.2
Liquids (Mbbl)(2)
382.8
EUR/well (total - Bcfe)
10.5
% liquids (of total EUR)(2)
22%
Liquids yield (bbls/MMcf)
43
4,000
6 Upper Montney wells - MFB
3,000
Well economics(4)
IRR
94%
NPV ($MM)
16.2
D&C costs ($MM)
10.0
Operating & transportation costs(5) ($/boe)
5.00
Average royalty rate(6)
16%
2,000
1,000
0
0
1
2
3
4
(5)
(6)
6
Cumulative raw gas (Bcf)
UM Actuals MFB (6 wells)
(1)
(2)
(3)
(4)
5
7
8
9
10
9 Bcf UM Raw Gas
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%.
Well economics are calculated on a before-tax basis using flat pricing assumptions: US$4.00/MMBtu Nymex; US$90.00/bbl WTI; 0.9 US$/C$ exchange rate. Well economics do not reflect expected
future capital expenditure and operating cost savings tied to commissioning of c-62-A water facility.
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 $2.4 MM per well is paid out, then 27% (natural gas) and 20% (liquids) thereafter. Royalty includes BC government cost allowance and excludes
average gross overriding royalty of 2.5% within the Main Fault Block.
10
Illustrative well economics - Lower Montney
Illustrative well economics
Canbriam development well vs. type curve
Main Fault Block (MFB) – Lower Montney
Drilling locations(1)
7,000
149
Well properties
Raw Gas Production (Mscf/d)
6,000
5,000
Raw gas type curve (Bcf)(2)
8.0
Sales gas (Bcf)(3)
7.3
Liquids (Mbbl)(2)
165.9
EUR/well (total - Bcfe)
8.3
% liquids (of total EUR)(2)
12%
Liquids yield (bbls/MMcf)
21
4,000
2 Lower Montney wells
3,000
Well economics(4)
IRR
36%
NPV ($MM)
6.3
D&C costs ($MM)
10.2
Operating & transportation costs(5) ($/boe)
5.60
Average royalty rate(6)
14%
2,000
1,000
0
0
1
2
3
4
5
6
7
8
9
10
Cumulative raw gas (Bcf)
8 Bcf LM Raw Gas
(1)
(2)
(3)
(4)
(5)
(6)
LM Actuals (2 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%.
Well economics are calculated on a before-tax basis using flat pricing assumptions: US$4.00/MMBtu Nymex; US$90.00/bbl WTI; 0.9 US$/C$ exchange rate. Well economics do not reflect expected
future capital expenditure and operating cost savings tied to commissioning of c-62-A water facility.
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 $2.5 MM per well is paid out, then 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.
11
Main Fault Block type well economic sensitivities
$25
120%
$20
80%
NPV10 ($MM)
Rate of return
100%
60%
40%
$15
$10
$5
20%
0%
$0
Low ($3.50/$70) Base ($4.00/$80) High ($4.50/$90)
Low ($3.50/$70) Base ($4.00/$80) High ($4.50/$90)
Price sensitivity
Price sensitivity
Upper Montney
Lower Montney
Upper Montney
Lower Montney
Main Fault Block type wells show strong economic returns under different pricing scenarios
12
Downhole choke strategy has improved decline rates
Advantages of using downhole chokes

Manages 1st year production declines
and fosters stable production
Altares c-B27-H Well – Upper Montney
Enhances EUR by maintaining bottomhole pressure; avoids shock to the
reservoir and possible relative
permeability issues
15.0
30.0
14.0
28.0
13.0
26.0
12.0
24.0
11.0


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
22.0
Sept 2014: Post-turnaround
flush production
10.0
Gas rate (MMcf/d)

9.0
8.0
7.0
20.0
18.0
Jan 2014: upsized choke
incremental 1.47 MMcf/d
16.0
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)

CTD: Oct 31, 2014 = 2.228 bcf
Canbriam’s use of downhole chokes optimizes the over-pressured reservoir
13
Infrastructure strategy supports development & lowers costs
100% owned and operated Infrastructure

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
c-64-H

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)
c-44-H

Source water pipeline extension & water hub facility scheduled start-up H1 2015
c-33-H
d-27-H
c-27-H
b-34-H
c-23-H
b-24-H
c-17-H
c-4-H
Altares processing
facility
expansion
Altares
processing
facility
expansion
d-93-A
450
b-97-A
c-84-A
400
Potential future
expansion of
b-72-A to 400 MMcf/d
350
300
MMcf/d
15-1
b-74-A
d-63-A
a-62-A
250
a-54-A
200
150
b-72-A Train 1, phase 2: 80 MMcf/d
Under
construction
100
d-34-A
Sales line
Gas gathering line
Produced water line
Future source water line
Infield water line
b-24 H Facility
b-72 A Facility (2015)
c-62-A Water treatment
and recycling station
b-72-A Train 1, phase 1: 80 MMcf/d
50
b-24-H: 50 MMcf/d current capacity
0
2013
2014
2015
2016
14
Integrated water solution is a strategic advantage
1
Sourcing
Canbriam - Altares

20-year permit to access up to 10,000 m3/day of lowcost fresh water from Williston Lake

Includes piping to service multiple frac operations
simultaneously
C-62-a
water treatment &
storage hub
2 Water treatment & recycle

Allows for continuous frac flow back while supplying
treated water to other frac operations

Eliminates need for water trucking in Main Fault Block
3
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
~75% complete
C-62-a hub
$20 MM
~60% 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
15
b-72-A facility: scalable design for efficient development
C-62-a Water hub
H1 2015E commissioning
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
Q1 2015E commissioning
September 2013
16
Maintaining operational & financial flexibility through 2015
Base case:
Maintenance case:


Fully funded in 2015: drop to 3-rig program

Complete infrastructure build-out:
Fully funded in 2015; 4-rig program


~90% of expected 2015 condensate production hedged at
WTI ~C$98
Complete infrastructure build-out:

b-72-A Train 1, Phase 1: 80 MMcf/d (Q1 2015E)

b-72-A Train 1, Phase 2: 80 MMcf/d (Q4 2015E)

C-62-A water hub (H1 2015E)

Funding required to support Train 2, Phase 1 & 2 of
b-72-A (incremental 240 MMcf/d)

Delivers ~40,000 Boe/d of exit production capacity in 2015

b-72-A Train 1, Phase 1: 80 MMcf/d (Q1 2015E)

b-72-A Train 1, Phase 2: 80 MMcf/d (Q4 2015E)

C-62-A water hub (H1 2015E)

Defer build-out of b-72-A Train 2, Phase 1 & 2

Expect to generate EBITDA in excess of capital expenditures
starting in 2016

Require 2-rigs to sustain full production in 2016E
Altares processing facility expansion – Maintenance case
Altares processing facility expansion – Base case
450
450
400
400
Potential future
expansion of
b-72-A to 400 MMcf/d
350
300
Defer expansion of
b-72-A Train 2
350
300
250
250
200
200
b-72-A Train 1, phase 2: 80 MMcf/d
150
Under
construction
100
b-72-A Train 1, phase 1: 80 MMcf/d
150
b-72-A Train 1, phase 2: 80 MMcf/d
Under
construction
100
b-72-A Train 1, phase 1: 80 MMcf/d
50
50
b-24-H: 50 MMcf/d current capacity
b-24-H: 50 MMcf/d current capacity
0
0
2013
2014
2015
2016
2013
2014
2015
2016
17
Operating environment supports development plan

Attractive fiscal regime in BC

Drilling credits & minimal retention drilling required

Supportive First Nations

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
Spectra T North
Gas transmission
Mile post 73 NGL
terminal - PPL
NGLs
Liquids
transportation
Fort St. John
Williston Lake
Taylor
condensate
terminal PPL
Station 2 - Spectra
Canbriam enjoys a low royalty burden in BC, a positive working relationship with stakeholders and easy
access to operating infrastructure
18
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 zone); 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
19
Hedge positions as of November 30, 2014
Natural gas
Liquids
MMcf/d
Bbls/d
30
25
$5.00
3,500
3,000
$3.66
$3.53
$120.00
$96.04
$98.75
$97.35
$4.00
2,500
20
$3.00
$80.00
2,000
15
$2.00
1,500
10
$40.00
1,000
$1.00
5
500
0
$0.00
2014
2015
0
$0.00
2014
2015
2016
Volume hedged
Volume hedged
AECO weighted average price (C$/gj)
WTI weighted average price (C$/bbl)
20
Key investment highlights
Prolific Montney
asset
Large, low risk, high
return drilling
inventory
Top decile well
economics
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

46.3mmboe of gross 1P Reserves (pre-tax PV10 of $510 million)(1)

110 mmboe of gross 2P Reserves (pre-tax PV10 of $1,081 million)(1)

100% working interest and operatorship in core lands

686 net locations in the Altares development area representing ~18 years of drilling inventory

High reservoir pressure and use of down-hole chokes limits declines and facilitates rapid growth

Extensive operating history in the Montney

High EURs in the primary Altares development area, with liquid yields up to 43 bbl/MMcf

Expected IRRs in the main fault block range from 90+% (Upper Montney, 2/3rd of inventory) to 30+% (Lower
Montney)(2)

Profitable in a ~US$2.50 NYMEX pricing environment

100%-owned gathering and processing facilities under expansion to 130 mmcf/d gas by Q1 2015 and 210
mmcf/d by Q4 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 and GE
(1) Based on GLJ reserve report dated December 31, 2013.
(2) Pricing assumptions: US$4.00/mmbtu Nymex; US$90.00/bbl WTI; 0.90 US$/C$ exchange rate.
21
Supplemental information
A focused, liquids-rich Montney growth company
Resource.
•
•
•
•
•
Differentiated Montney resource with unique geology
Liquids-rich (~50% of 61,000 net acres)
Large low-risk, high return drilling inventory
Favorable operating environment
Best in class well economics
Innovation.
• Optimization of development through top tier sub-surface reservoir
characterization
• Maximizing value through a well defined, integrated operating strategy
Collaboration.
•
•
•
•
Multi-disciplinary, integrated team approach
Experienced management team
Strong sponsorship
Solid financial position with significant liquidity
23
Significant reserve growth with high liquids content

Reserve evaluation conducted by GLJ Petroleum Consultants as of December 31, 2013
Summary of Gross Reserves as of 12/ 31/ 2013
Category
Natural Gas (Bcf)
Proved Developed
Proved Undeveloped
NGLs (MMbbls)
Total (MMBoe)
(1)
PV-10% ($MM)
(2)
Net Locations
71.5
145.7
3.1
7.0
15.1
31.2
$274
$236
25
28
Total Proved
217.2
10.1
46.3
$510
53
Probable
301.9
13.2
63.5
$571
40
519.1
23.3
109.8
$1,081
93
Total Proved + Probable
Reserve Category Breakdown
2P Reserve Growth
2P Reserves by Commodity
(MMboe)
23
20
15
7
1
8
2009
87
59
42
21
2010
Gas
Proved
developed
nonproducing
3.1%
Proved
undeveloped
28.4%
Proved
producing
10.7%
Liquids
21.2%
Probable
57.8%
Gas
78.8%
2011
2012
2013
Liquids
A significant portion of Canbriam's 2P reserves are condensate which receive premium pricing in Canada
(1)
(2)
Company interest, before royalties.
Before tax and based on GLJ pricing as of 1/1/14.
24
Montney depositional model

Montney sediment source is a combination of perennial
and ephemeral rivers, and aeolian processes
transported down-slope via submarine fans
Town depocenter
Fort St. John


The combination of the above high volume episodic
deposition augmented by continuous pelagic sediment
allows for significant thicknesses of sediment to be
deposited over a short time period (i.e. 3 to 4 million
years)
Edmonton
Over Canbriam's Altares Property this has resulted in
~1,100 ft of sediment deposition – providing an
extremely thick and exploitable reservoir package
Calgary
Altares depocenter
Groundbirch depocenter
25
b-72-A facility: scalable design for efficient development
September 4, 2014
December 19, 2014
26
Robust historical netbacks ($/boe)
$39.07
$3.69
Realized price:
Cash royalties
$29.58
$0.70
$33.23
$0.88
$4.04
$1.37
$3.15
$1.82
$6.56
Operating expenses
$1.09
Transportation expenses (1)
$30.41
$26.94
Cash operating netback
$21.23
2012
2013
Realized prices
Natural gas ($/mcf)
NGLs ($/bbl)
Q3 2014 YTD
$3.59
$90.76
$3.53
$72.48
$5.00
$76.90
Benchmark prices
Henry Hub (US$/mmbtu)
AECO ($/GJ)
Station 2 ($/GJ)
WTI (US$/bbl)
$2.80
$2.26
$2.17
$94.21
$3.67
$3.01
$2.96
$97.97
$4.55
$4.56
$4.23
$99.61
Strong netbacks result from liquids component & low cost structure
(1)
Adjusted transportation expense excludes $95 thousand for the year ended December 31, 2013 related to the portion of the 50 MMcf/d firm commitment with Spectra that was not utilized during the period
and $699 thousand for the same period in 2012.
27
Composition of total liquids production
Realized prices - liquids (C$)
140.00
120.00
100.00
80.00
60.00
40.00
20.00
0.00
CONDENSATE ($/bbl)
PROPANE ($/bbl)
BUTANE ($/bbl)
PENTANE+ realized (C$/bbl)
2013
Production
WTI (C$/bbl)
2014 Q3 YTD
Production
Revenue
Pricing*
(%)
(%)
(% WTI)
Production
Production
Revenue
Pricing*
(%)
(%)
(% WTI)
Butane (bbl/d)
325
4%
7%
55 - 60%
361
4%
5%
55 - 60%
Propane (bbl/d)
315
4%
2%
15 - 20%
359
4%
2%
15 - 20%
Condensate (bbl/d)
1,200
15%
43%
90 - 95%
1,129
12%
31%
90 - 95%
Natural gas (MMcf/d)
35.8
76%
49%
-
46.3
80%
62%
-
Total (boe/d)
7,800
100%
100%
9,600
100%
100%
Note:
Ignores FX impact on realized pricing. Condensate include pentanes plus production.
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]