BUILDING
OUR FUTURE
IN THE
MONTNEY
CAUTIONARY STATEMENT
Forward Looking Statements
This presentation contains certain forward–looking information and statements within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "may", "will", "project",
"should", "believe", "plans", "intends“, “forecast” and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the forgoing, this presentation contains forwardlooking information and statements pertaining to the following: the volumes and estimated value of Crew's oil and gas reserves; resource estimates and volumes in respect of Crew’s Montney lands in northeast British
Columbia (“NEBC”); the volume and product mix of Crew's oil and gas production; production estimates including 2017 forecast average and exit productions and production per share growth; the recognition of significant
resources in the Montney region of NEBC; future oil and natural gas prices and Crew's commodity risk management programs; future liquidity and financial capacity; future results from operations and operating metrics;
forecast 2017 net debt; forecast 2017 cash flow and year end bank debt; future costs, expenses and royalty rates; future interest costs; the exchange rate between the $US and $Cdn; future development, exploration,
acquisition and development activities, infrastructure build out and related capital expenditures and the timing thereof; the amount and timing of capital projects; operating costs; the total future capital associated with
development of reserves and resources; methods of funding our capital program including possible non-core asset divestitures; and forecast reductions in well costs and operating expenses. In this presentation reference is
made to the Company's long range Montney growth scenario and economic analysis. All information derived therefrom are not estimates or forecasts of metrics that may actually be achieved. Such information reflects
internal projections used by management for the purposes of making capital investment decisions and for internal long range planning and budget preparation. Accordingly, undue reliance should not be placed on same.
The recovery, reserve and resources estimates of Crew's reserves and resources provided herein are estimates only and there is no guarantee that the estimated reserves or resources with be recovered. In addition,
forward-looking statements or information are based on a number of material factors, expectations or assumptions of Crew which have been used to develop such statements and information but which may prove to be
incorrect. Although Crew believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because Crew can give
no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: the impact of
increasing competition; the general stability of the economic and political environment in which Crew operates; the timely receipt of any required regulatory approvals; the ability of Crew to obtain qualified staff, equipment and
services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects in which Crew has an interest in to operate the field in a safe, efficient and effective manner; the ability of Crew to obtain
financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development and exploration; risks associated with the degree of
certainty in resource assessments; the timing and cost of pipeline, storage and facility construction and expansion and the ability of Crew to secure adequate product transportation; future commodity prices; currency,
exchange and interest rates; regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which Crew operates; and the ability of Crew to successfully market its oil and natural gas
products. There are a number of assumptions associated with the potential of resource volumes assigned to lands evaluated in Crew's Montney area of operations in NEBC, including the quality of the Montney reservoir,
future drilling programs and the funding thereof, continued performance from existing wells and performance of new wells, the growth of infrastructure, well density per section and recovery factors and discovery and
development of the lands evaluated in Crew's Montney area of operations in NEBC necessarily involves known and unknown risks and uncertainties, including those identified in this presentation and including the business
risks discussed in Crew's annual and quarterly MD&A and other continuous disclosure documents.
Crew’s 2017 budget guidance and related targets and forecasts disclosed herein are best estimates based on certain assumptions including, without limitation, operating results, known fiscal regimes, commodity prices and
risk management contracts and will be regularly monitored by management. Our objective will be to proactively manage our capital program as it relates to operational success and fluctuating commodity prices with a priority
to maintain financial flexibility and achieve our production guidance. Crew will closely monitor the budget and financial situation throughout the year to assess market conditions and will quickly adjust budget levels or pace of
development in accordance with commodity prices and available funds from operations.
The forward-looking information and statements included in this presentation are not guarantees of future performance and should not be unduly relied upon. Such information and statements; including the assumptions
made in respect thereof, involve known and unknown risks, uncertainties and other factors that may cause actual results or events to defer materially from those anticipated in such forward-looking information or statements
including, without limitation: changes in commodity prices; the potential for variation in the quality of the Montney formation; changes in the demand for or supply of Crew's products; unanticipated operating results or
production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans of Crew or by third party operators of Crew's properties, increased debt levels or debt
service requirements; inaccurate estimation of Crew's oil and gas reserve and resource volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of inadequate insurance coverage; the
impact of competitors; and certain other risks detailed from time-to-time in Crew's public disclosure documents, (including, without limitation, those risks identified in this presentation and Crew's Annual Information Form).
The forward-looking information and statements contained in this presentation speak only as of the date of this presentation, and Crew does not assume any obligation to publicly update or revise any of the included forwardlooking statements or information, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.
2
BUILDING OUR FUTURE IN THE MONTNEY
16+ billion
+40%
BOE of TPIIP
resource
Forecast Montney production growth
from Q4 ‘16 to Q4 ‘17
~5,780
Identified drilling
locations(1)
285,000+
Net acres in the Montney
FINANCIAL
STRENGTH & DISCIPLINE
275+mmcf/d
~71%
Condensate as a percentage of
forecast liquids production in 2017
$2 billion
2016 BT NPV10
Long-term takeaway capacity
to diverse markets
PEOPLE
ASSETS
Identified locations are the total number of risked Contingent (2,056) and Prospective (3,377) resource locations as well as the 2P booked undeveloped Montney locations (356) identified in Crew’s annual year end independent resource
evaluation and independent reserves evaluation, both prepared in accordance with the COGE Handbook provisions and NI 51-101. See complete details on the resource evaluation and reserves evaluation in presentation appendix
(1)
3
TECHNOLOGY
ABOUT CREW (TSX: CR)
Track Record of Successful
Montney Execution
• Growth-oriented Montney producer with large, contiguous land
base in NE BC
Montney Production(2) (BOE/D)
• Access to diversified markets with operated infrastructure and
increasing liquids production leads to top quartile netbacks
35,000
• >31,000 boe/d forecast 2017 exit production (24,000 - 26,000 boe/d
20,000
forecast annual average)
30,000
25,000
Forecast
Light oil bopd
NGLs boepd
Gas boepd
15,000
10,000
• $535MM of total debt capacity ($300MM senior notes and $235MM credit
facility currently undrawn)
5,000
-
2009 2010 2011 2012 2013 2014 2015 2016 2017 2017
Exit
• ~$600MM market cap / $900MM EV (149.8MM shares O/S @ $4.00/sh)
P+P Reserves(3) (MMBOE)
323.9
350.0
Liquids mmbbls
300.0
50% hedged
On forecast 2017 gas
sales at $3.62/mcf(1)
50% hedged
On forecast 2017 light oil
& ngl sales at $68.17/bbl
(2)
(3)
4
Adjusted to reflect Crew’s average natural gas heat content 1.24 GJ / mcf.
Reflects production from Greater Septimus and Tower (Tower is included as ‘Other’ in financial statement disclosure).
Based on Crew’s annual year end independent reserves evaluations.
246.5
250.0
201.9
200.0
150.0
99.2
100.0
50.0
(1)
Gas mboe
15.3
21.6
27.7
2008
2009
2010
46.7
48.1
2011
2012
-
2013
2014
2015
2016
TRACK RECORD OF PROFITABILITY SUPPORTED BY
LOW CASH COSTS
2016 PDP FD&A Costs
2016 Cash Costs
($US/boe)
($US/boe, net of royalties)
$30
Canadian Co's
US Co's
US Co's
Median
$50
Median
$25
$40
$20
$30
$15
$20
$10
$10
$5
$0
$0
ECA
COG
AAV
CHK
SGY
PEY
CJ
CR
NBL
BIR
VET
WCP
XEC
TVE
RRC
AREX
KEL
BTE
SWN
CLR
SN
DVN
PXD
OAS
VII
TOG
CPG
EOG
SPE
CXO
RRX
NFX
BBG
APC
PE
EGN
APA
PDCE
SM
WLL
5
(1)
Source: Macquarie Capital Markets Canada; May 30 ‘17
Canadian Co's
AAV
PEY
SWN
COG
BIR
BNP
CR
RRX
RRC
XEC
ARX
CLR
VII
RMP
WCP
TVE
PDCE
KEL
PRQ
VET
ERF
NBL
DVN
EOG
EGN
NFX
CHK
CXO
SGY
TOG
PE
SM
CPG
PXD
APC
AREX
ECA
BTE
POU
SPE
APA
WLL
SN
CJ
OAS
BBG
$60
LONG-TERM TOP QUARTILE CAPITAL EFFICIENCIES
DRIVE STRONG RECYCLE RATIOS
3-Year Proved Developed FD&A Costs
3-Year Proved Developed Recycle Ratio
($US/boe, net of royalties)
$60
($US/boe, net of royalties, including hedging)
3.5x
Canadian Co's
Canadian Co's
US Co's
Median
$50
US Co's
3.0x
Median
2.5x
$40
2.0x
$30
1.5x
$20
1.0x
$10
0.5x
COG
ERF
RRC
BIR
BNP
PEY
AAV
CR
ARX
CJ
XEC
SWN
VET
SGY
CHK
AREX
TVE
WCP
RRX
VII
NBL
OAS
SN
PXD
APC
CLR
TOG
EOG
CXO
NFX
KEL
CPG
PE
DVN
POU
WLL
SM
RMP
ECA
PDCE
BTE
EGN
APA
BBG
6
(1)
Source: Macquarie Capital Markets Canada; May 30 ‘17
ERF
COG
ARX
VET
OAS
PEY
BNP
CR
SGY
BIR
RRX
RRC
WCP
AAV
CXO
AREX
CJ
CLR
CPG
PXD
XEC
TOG
SN
NBL
PE
EOG
TVE
APC
WLL
NFX
RMP
VII
CHK
PDCE
SWN
BBG
SM
EGN
DVN
BTE
APA
KEL
POU
ECA
0.0x
$0
VALUATION / PROFITABILITY DISCONNECT
14
US Co's
Revenue - PDP FD&A Costs - Cash Costs =
PXD
Full Cycle Profitability
Canadian Co's
CXO
12
XEC
Increasing
valuation
EOG
PE
EGN
EV/DACF 2018
10
APA
NFX
SM
8
POU
ECA
BBG
KEL
PDCE
CHK AREX RRC
NBL
WLL APC
COG
CLR
WCP
VII
DVN
VET
AAV
OAS
BTE
ARX
PEY
TOG
SN
6
RMP
CJ
CPG
SWN
BIR
SGY
BNP
RRX
ERF
CR
4
TVE
2
$(50)
7
(1)
Increasing profitability
$(40)
Source: Macquarie Capital Markets Canada; May 30 ‘17
$(30)
$(20)
$(10)
$-
3 Year Full Cycle Profit (ex-hedge) ($US/boe, net of royalties)
$10
$20
RISING NETBACKS & LOWER COSTS
High Quality Montney Assets Support Strong Q1 2017 Results
$25
Top Quartile Operating Netbacks (Pre-Hedging)
Among Montney-Focused Peers ($/boe)
Top Quartile Montney Operating Costs Among
Montney-Focused Peers ($/boe)
$11
$20
$17.55
$9
Group Average = $17.85
Operating Costs ($/boe)
Operating Netback ($/boe)
$10
$19.88
$15
$10
$8
$7
Group Average = $5.73
$5.35
$6
$5
$4
$3.34
$3
$5
$2
$1
$0
1
8
5
2
CR
Montney
3
CR Corp
9
4
7
11
8
6
10
$0
Source: Public Filings. Companies included in above analysis include VII, NVA, TET, PEY, POU, BIR, KEL, AAV, DEE, PPY, SRX.
2
3
7
5
8
4
CR Corp
10
1
11
CR
Montney
6
9
MASSIVE LAND POSITION IN THE ‘SWEET SPOT’
OF THE MONTNEY
13% of land
Has Upper Montney reserves
assigned
Crew Goose
Disposition
<1% of land
Has Lower Montney reserves
assigned
446 netsections
9
Repsol
Crew Energy Inc.
Canadian Natural Res.
Leucrotta Exploration
Arc Resources
Encana
Painted Pony Petroleum
Shell Canada
Broker Lands
Kelt Exploration
Penn West Petroleum
Suncor Energy
Source: RBC Capital Markets.
Tourmaline Oil
266
113
67
Wet Gas Sections
Oil / Condensate Sections
Dry Gas Sections
CREW MONTNEY “STRATIGRAPHIC STACK”
3 HZ Wells
West Portage
Groundbirch
3 HZ Wells
1
2
AA
5
B
77 HZ Wells
1 HZ Well
Goose
Septimus
10 HZ Wells
Tower
35
2
11
Doig
23
1
A
2
54 HZ Wells
West Septimus
Attachie
42
1
9
Upper Montney
2 HZ Wells
7
3
2
3
Monias High
1
Lower Montney
1,000 Feet
C
150 Crew HZ wells
drilled to Q1, 2017
Belloy
10
•
•
•
•
Crew recognizes four major clinoform units in the Upper Montney (AA, A, B, C)
The majority of Crew horizontals (70%) have been drilled in the “B” clinoform
The “Lower B” and “C” clinoforms are still essentially undrilled
The Lower Montney unit also has excellent prospectivity, especially at Septimus, Tower and Attachie
WEST SEPTIMUS
512
Economics(1):
Half Cycle
$4.3
$3.5
10000
1,029
1,029
9000
0
0
8000
NGLs (mbbls)
197
197
Sales Gas (bcf) (raw: 5.0 bcf)
4.7
4.7
980
980
1 Month IP (boe/d)
Oil (mbbls)
Total Reserves (mboe)
NPV10 ($MM)
PIR (10% discount)
ROR Before Tax (%)
F&D ($/boe)
Payout (years)
Daily Gas Production (mcf/d)
Full Cycle
Capital Expenditures ($MM)
7000
6000
5000
4000
$3.1
$3.9
0.7
1.1
2000
42%
70%
1000
$4.39
$3.57
2.1
3000
0
0
50
100
150
200
250
300
350
400
Time (Days)
1.4
Economic Assumptions: Based on Sproule’s year end 2016 2P type wells for West Septimus; May 30, 2017 forward price deck as
follows: Cal ‘17: C$2.74/GJ AECO; US$50.25 WTI, $074 F/X; Cal ‘18: C$2.55/GJ AECO, US$50.35 WTI, $0.75 F/X; Cal ‘19:
C$2.35/GJ AECO, US$50.05 WTI, $0.75 F/X; Cal ‘20: C$2.37/GJ AECO, US$50.35 WTI, $0.76 F/X; Cal ’21 and thereafter:
C$2.45/GJ AECO, US$49.85 WTI, $0.76 F/X.
(2) Identified locations are the total number of risked Economic Contingent, development pending and development on hold
subcategories as identified in Crew’s annual year end independent resource evaluation prepared in accordance with the COGE
Handbook provisions and NI 51-101. See complete details on the resource evaluation in presentation appendix.
Up to 220 bbl/mmcf(3)
Outperformance of Initial
West Septimus Type Curve(4)(5)
04-24 (9)
07-30 (2)
10-16 (7)
8-22 (3)
(1)
11
Condensate - Rich
Identified Locations(2)
(3)
(4)
(5)
05-24 (3)
09-17 (5)
16-15 (6)
2016YE Sproule - 5.0Bcf 2P
Based on initial production data from Crew’s 7-30-82-19W6 well.
See the Appendix to this presentation for information on Type Wells.
Sproule’s 2015 vs 2014 figures represent average EUR per well for undeveloped locations assigned by Sproule in Crew’s annual
year end reserves reports.
SEPTIMUS: FREE CASH FLOW GENERATION
Economics(1):
Full Cycle
Half Cycle
Capital Expenditures ($MM)
$4.3
$3.5
1 Month IP (boe/d)
809
809
0
0
NGLs (mbbls)
169
169
Sales Gas (bcf) (raw: 5.6 bcf)
5.2
5.2
1,037
1,037
$2.3
$3.1
0.5
0.9
30%
48%
$4.15
$3.38
2.9
1.8
Oil (mbbls)
~$108 MM
104
$100
Free cash flow directed to fund
continued Montney growth
$80
NPV10 ($MM)
PIR (10% discount)
ROR Before Tax (%)
F&D ($/boe)
Payout (years)
(1)
(2)
12
Economic Assumptions: Based on Sproule’s year end 2016 2P type wells for Septimus; May 30, 2017 forward price deck as
follows: Cal ‘17: C$2.74/GJ AECO; US$50.25 WTI, $074 F/X; Cal ‘18: C$2.55/GJ AECO, US$50.35 WTI, $0.75 F/X; Cal ‘19:
C$2.35/GJ AECO, US$50.05 WTI, $0.75 F/X; Cal ‘20: C$2.37/GJ AECO, US$50.35 WTI, $0.76 F/X; Cal ’21 and thereafter:
C$2.45/GJ AECO, US$49.85 WTI, $0.76 F/X.
Identified locations are the total number of risked Economic Contingent, development pending and development on hold
subcategories as identified in Crew’s annual year end independent resource evaluation prepared in accordance with the COGE
Handbook provisions and NI 51-101. See complete details on the resource evaluation in presentation appendix.
$60
$MM
Total Reserves (mboe)
Free cash flow
generated ‘16 – ’19(3)
Identified Locations(2)
$40
$20
$2013
2014
2015
2016
Cash Flow
(3)
2017
2018
2019
(3)
Forecast
Capex
Cash Flow Assumptions for Forecast: Cal ‘17: C$3.13/GJ AECO, US$3.50 NYMEX; US$54.25 WTI, $076 F/X; Cal ‘18:
C$2.85/GJ AECO, US$3.05 NYMEX, US$55.00 WTI, $0.75 F/X; Cal ‘19: C$2.75/GJ AECO, US$2.90 NYMEX, US$55.00 WTI,
$0.75 F/X.
ULTRA CONDENSATE-RICH AREA IS NEW FOCUS AT
GREATER SEPTIMUS
Economics(1):
Half Cycle
Capital Expenditures ($MM)
1 Month IP (boe/d)
Condensate (mbbls)
Sales Gas (bcf)
3.5
892
NPV10 ($MM)
$5.7
1.3
ROR Before Tax (%)
131%
F&D ($/boe)
$4.82
Economic Assumptions: Based on Sproule’s year end 2016 2P type wells for Ultra-Condensate Rich area; May 30,
2017 forward price deck as follows: Cal ‘17: C$2.74/GJ AECO; US$50.25 WTI, $074 F/X; Cal ‘18: C$2.55/GJ AECO,
US$50.35 WTI, $0.75 F/X; Cal ‘19: C$2.35/GJ AECO, US$50.05 WTI, $0.75 F/X; Cal ‘20: C$2.37/GJ AECO,
US$50.35 WTI, $0.76 F/X; Cal ’21 and thereafter: C$2.45/GJ AECO, US$49.85 WTI, $0.76 F/X.
(2)
13
0.8
B7-30: 35,000 bbls condensate
in 125 days; avg CGR of 141
Crew 4-22 Pad
Drilling Operations
243
Total Reserves (mboe)
(1)
Crew 7-30 Pad
Drilling Operations
1,064
61
Payout (years)
C7-30: 60,000 bbls condensate in
180 days; avg CGR of 188
$4.3
NGLs (mbbls)
PIR (10% discount)
‘Ultra Condensate-Rich’
Crew 13-19 Pad
Drilling Operations
Crew 15-9 Pad
Montney 2017 Drilling Locations
Montney A Drilled Wells
Montney B Drilled Wells
Montney Lower B Drilled Wells
W. Septimus Facility
60 mmcf/d Capacity
Expanding to 120 mmcf/d
Montney C Drilled Wells
Lower Montney Drilled Wells
Crew Montney Acreage
‘Ultra Condensate Rich’ Area
>165 potential drill locations
Identified locations are the total number of risked Economic Contingent, development pending and development on hold subcategories as identified in Crew’s annual year end independent
resource evaluation prepared in accordance with the COGE Handbook provisions and NI 51-101. See complete details on the resource evaluation in presentation appendix.
(2)
Estimated in ‘ultra condensate-rich’ area,
up to 1/3 of W. Septimus locations
OUR MONTNEY ASSETS CAN GENERATE COMPELLING
RETURNS ACROSS VARIOUS PRICE & COST CYCLES
Project Area Cost Increase Effect on IRR
140
Project Area Price Increase Effect on IRR
180
$4.3MM
160
~70% IRR even with
25% cost escalation
120
140
100
80
$3.5MM
60
$3.5MM
IRR (%)
IRR (%)
120
100
80
60
40
40
20
20
0
0
Base Capital
5% Cost
Increase
Septimus ($3.5mm)
(1)
14
10% Cost
Increase
15% Cost
Increase
West Septimus ($3.5mm)
20% Cost
Increase
25% Cost
Increase
Condensate Rich ($4.3mm)
15% Price
Decrease
10% Price
Decrease
5% Price
Decrease
Septimus
Base Price
West Septimus
5% Price
Increase
10% Price
Increase
15% Price
Increase
Condensate Rich
Economic Assumptions: Based on Sproule’s year end 2016 2P type wells for Septimus, W. Septimus, Ultra-condensate rich, and Tower; May 30, 2017 forward price deck as follows: Cal ‘17: C$2.74/GJ AECO; US$50.25 WTI, $074 F/X; Cal ‘18: C$2.55/GJ AECO, US$50.35
WTI, $0.75 F/X; Cal ‘19: C$2.35/GJ AECO, US$50.05 WTI, $0.75 F/X; Cal ‘20: C$2.37/GJ AECO, US$50.35 WTI, $0.76 F/X; Cal ’21 and thereafter: C$2.45/GJ AECO, US$49.85 WTI, $0.76 F/X.
FUTURE GROWTH OPPORTUNITIES
90+
Over-pressured, liquids-rich natural gas areas
ATTACHIE
• 1,000’ thick pay (Upper + Lower Montney)
• Several prolific offsetting producers in
Upper & Lower Montney
~97
Attachie
GOOSE
•
•
• Multiple prospective zones
• Successful pilot wells prove resource with
several prolific offsetting producers in the
Lower Montney
Goose
• Crew Lower Montney production exceeding
5.6 Bcf type curve (see below)
Greater
Septimus
Disposition price
$49MM
18,441 net acres,
$2,657/acre
No production or
assigned reserves
Avg. Daily Rate
6,000
Crew Septimus 12-35
Sproule 5.6 Bcf Type Curve(2)
5,000
Groundbirch
2018/19 Planned Facility
120 mmcf/d Capacity
Groundbirch
GROUNDBIRCH
• Expected development of 15-20
wells per section in Upper Montney
• Ideally situated for proposed
N. Montney Mainline access
~156
net sections
Gas production (mcf/d)
•
LOWER MONTNEY
net sections
90+ Wells
3 Lower Montney Zones
Lower Montney identified
locations at Greater Septimus(1)
4,000
3,000
2,000
1,000
100+ Wells
1 Lower Montney Zone
0
1
3
5
7
9 11 13 15 17 19 21 23 25 27 29 31 33 35
Time (months)
(1)
15
(2)
Identified locations are the total number of risked Economic Contingent, development pending and development on hold subcategories as identified in
Crew’s annual year end independent resource evaluation prepared in accordance with the COGE Handbook provisions and NI 51-101. See complete details on the resource evaluation in presentation appendix.
See the Appendix to this presentation for information on Type Wells
GROUNDBIRCH
Delineation Area with Long-Term Upside
•
Similar liquids content to Septimus at 30-40 bbls / mmcf,
60% condensate
•
Large pay thickness (500 ft. – Upper Montney) with
expected development of 15-20 wells / section in Upper
Montney
•
156 sections of land: recent land sale illustrates value of
area land at $3.53MM per section. Read through for
Crew at ~$550MM
Crew 2-4 Pad
Completion Operations
W. Septimus Facility
60 mmcf/d Capacity
Expanding to 120 mmcf/d
Acquisition of
10 Sections of
Surface Rights
2018
2019
Recent Landsale
$3.5MM / Section
TCPL Saturn
Meter Station
Groundbirch Development Plan
2017
Groundbirch
2018/19 Planned Facility
120 mmcf/d Capacity
2020+
Delineation
Build Gas Plant + Pipeline from
W. Septimus to Saturn Meter Station
Area Development
16
~156
net sections
Montney Phase 1 Locations (230)
Montney B Drilled Wells
Montney C Drilled Wells
Crew 2017/2018 Pipeline Construction
Proposed TCPL N. Montney Mainline Project
Crew Operated Pipeline
Crew Montney Acreage
ATTACHIE
Pilot Wells Successful
ARC Montney
Wells
Crew 10-22
10.5 mmcf/d
15 bbls/mmcf Condy,
4 Fracs
• Over-pressured with liquids-rich natural gas
• Large pay thickness (1,000’ – Upper + Lower Montney)
• High condensate rates in offsetting wells
• Ideally situated to access proposed N. Montney
Mainline
• Crew 10-22 well tested at 10.5 mmcf/d
@ 1,230 psi FCP (after 4 days flow)(1)
Crew C-20-E
Final Rate 4.4 mmcf/d
4 Fracs
Crew 15-36
Final Rate 7.8 mmcf/d
10 bbls/mmcf Condy
19 Fracs
• Crew 15-36 well tested at 7.9 mmcf/d
@ 1,250 psi FCP (after 2.5 days flow)(2)
• Several prolific offsetting producers in Upper and
Lower Montney
(1)
(2)
17
Reflects stabilized natural gas rate at end of 4 day test period.
Reflects stabilized natural gas rate at end of 2.5 day test period.
Crew 3-12
Final Rate 2.4 mmcf/d
5 Fracs
~97
net sections
Crew 10-22 Montney Well
Crew 15-36 Montney Well
Spectra T North Pipeline
Proposed TCPL N. Montney Mainline Project
Crew Montney Acreage
MULTIPLE MARKET ACCESS POINTS
•
Long-term transportation capacity and market planning
facilitates growth to ~60,000 boe/d to 2019
Flatrock
•
•
Three pipeline options running west, east and
south provide access to North American markets
Diversified gas marketing strategy offers exposure to
Chicago City Gate, AECO, ATP, Station II & Sumas
markets
Attachie
West
Septimus
Alliance Pipeline
1.6 Bcf/d
Portage
Tower
Minimum of
275 mmcf/d
Minimum of
2,200 bbls/d
Condensate and light oil with
long-term transportation
capacity secured
18
Long-term takeaway
capacity with operational &
market diversification
TCPL
N. Montney Project
Septimus
1.5 Bcf/d
Spectra T-North
Ft. Nelson Mainline
1.4 Bcf/d
Groundbirch
Spectra T-North
Ft. St. John Mainline
0.85 Bcf/d (post expansion)
Crew Operated Pipeline
Crew 2017/2018 Pipeline Construction
Alliance Operated Pipeline
Spectra Westcoast Operated Pipelines
Pembina Peace Condensate Pipeline
TCPL Operated Pipeline
Proposed TCPL North Montney Mainline Project
Crew Operated Gas Plant
Crew Planned Gas Plant
Spectra McMahon Gas Plant
TCPL Saturn Meter Station
Crew Montney Acreage
FIRM SERVICE ARRANGEMENTS & STAGED
PROCESSING SUPPORT GROWTH PLAN
Transportation
400,000
Processing
TCPL/Nova: 60 mmcf/d firm increasing to 120 mmcf/d (Jun ‘19)
Groundbirch: 120 mmcf/d (Q4 ‘18)
Spectra:
13 mmcf/d firm increasing to 30 mmcf/d (Apr ‘17)
W. Septimus: 60 mmcf/d expanding to 120 mmcf/d (Q4 ‘17)
Alliance:
100 mmcf/d firm (+ 25 priority interruptible available)
Septimus:
60 mmcf/d
Numbers above do not include access to interruptible or
shorter term transportation opportunities
300,000
* Additional capacity post-2020 is available on the TCPL / Nova System
*
200,000
100,000
0
Jan-17
19
Jul-17
Jan-18
Jul-18
Jan-19
Jul-19
Jan-20
ADVANTAGES OF GAS MARKET DIVERSITY
$4.00
$3.50
Commencement of Alliance Pipeline service
and initiation of diversified contract portfolio
Natural Gas Prices ($C/MCF)
$3.00
$2.50
$2.00
Stn 2
$1.50
10%
Crew’s
Gas Market
Diversity
$1.00
Enhanced gas price
$0.50
ATP
45%
19%
Q1, 2017
Chicago
City
Gate
26%
AECO 5A
Enriched by heat content + diversified portfolio
$Nov-15
Dec-15
Crew Realized Price (1)
20
(1)
Wellhead price before impact of hedging.
Q1 2016
Chicago City Gate at ATP
Q2 2016
Q3 2016
AECO 5A
Q4 2016
ATP (CREC)
Q1 2017
Stn #2
BUILDING BLOCKS ARE IN PLACE
Financial Strength
+40% Growth
~1.5x debt / FFO(1)
Forecast Montney production Q4 ‘16 – Q4 ‘17
Access
to
Infrastructure
And diversified markets
Massive Resource
16+ billion boe TPIIP
Efficiency Improvements
Lower costs, higher IPs and EURs per well
Increasing Condensate
Focus on ultra condensate-rich development
21
(1)
Forecast YE ‘17 net debt to Q4 ‘17 annualized funds from operations.
Contact Info:
Suite 800, 250 - 5th Street SW
Calgary, Alberta T2P 0R4
Telephone: (403) 266-2088
Email: [email protected]
22
Dale O. Shwed, President & CEO
John G. Leach, Senior Vice President & CFO
Robert J. Morgan, Senior Vice President & COO
Appendix
2017 CAPITAL PROGRAM AND FORECAST
2017
$131
Capex (mm)
$200
Volume
Year-end net debt (mm)
$275
Natural Gas
~1.5x
35,000 GJ/Day
2017
Swap
AECO
$2.89/GJ
27,500 mmbtu/Day
2017
Swap
Chicago
C$3.95/mmbtu
5,000 GJ/Day
2017
Physical
Station 2
C$2.50/GJ
2,500 GJ/Day
2018
Swap
AECO
C$2.62/GJ
5,000 mmbtu/Day
2018
Swap
Chicago
C$4.23/mmbtu
5,000 mmbtu/Day
2018
Swap
NYMEX
US$3.05/mmbtu
Feb – June 2017
Swap
$C WTI / bbl
C$68.94
Jan – Dec 2017
Swap
$C WTI / bbl
C$68.02
Feb – June 2017
Swap
$C WCS-WTI / bbl
(C$19.40)
Debt to annualized Q4 CF
Assumptions:
Production guidance (boepd)
Pricing
Gas
(AECO-C$/mcf)
Oil
(WTI-C$/bbl)
WTI to WCS diff.
24
Hedging Summary as of July 4, 2017
Cash Flow (CF) (mm)
24,000 to 26,000
$3.08
$73.00
24%
$0.74
1,000 bopd
Interest rate-Bank debt
4.5%
1,750 bopd
Interest rate-High yield
6.5%
500 bopd
Royalties
6-8%
$5.50-6.00
Transportation ($/boe)
$2.25-2.50
G&A ($/boe)
$1.25-1.50
Interest Expense ($/boe)
$2.25-2.50
Derivative
Reference
Price
Oil
FX ($US/$CDN)
Op. costs ($/boe)
Period
SUMMARY OF NEW TERM DEBT
25
Issuer:
•
Crew Energy Inc. (the “Company”)
Issue:
•
$300 million senior unsecured notes (the “Notes”)
Coupon:
•
6.5%
Issue Ratings:
•
DBRS: B
Term:
•
Seven years (7NC3)
Ranking:
•
Senior unsecured ranking pari passu with all existing and future senior unsecured indebtedness
Use of Proceeds:
•
The Company plans to use the net proceeds from the sale of the Notes for the redemption of the 2020
Notes, for a non-permanent repayment of existing indebtedness under its credit facility, and for general
corporate purposes
Optional Redemption:
•
The Company may, at its option, redeem all or part of the Notes at any time prior to March 14th, 2020 at
the make‐whole price and on or after March 14th, 2020, at the agreed upon redemption prices
Equity Clawback:
•
Within the first three years, up to 35% of the issue may be redeemed at a premium of par plus the
coupon with the proceeds of an equity offering
Change of Control:
•
Offer to repurchase at 101%
Covenants:
•
Substantially the same as the Company's existing notes
S&P: B
STABLE ASSET:
LLOYDMINSTER HEAVY OIL
Lloydminster
ALBERTA
SASKATCHEWAN
• Currently in sales process
BRIGHTSAND
• 73,326 net acres of land in the area;
average WI of 93%
• Q1 2017 production of 1,865 boe/d
• $50MM disposition closed Q3 ’15
SWIMMING
Lloydminster
FOREST
BANK
LASHBURN
WILDMERE
VIKING / KINSELLA
LOW LAKE
UNWIN / EPPING
NEILBURG
BALDWINTON
• 2017 capital $7.5MM & forecast annual
production of 2,000 boe/d
UNITY
2015 Disposition Area
Crew 100% W.I. Dulwich
Heavy Oil Facility
26
LUSELAND
2016 RESERVES & RESOURCE HIGHLIGHTS
Montney Reserves and Resource Growth and Improving Capital Efficiencies
2016
Change
2016
Change
(mmboe)
(after production)
(per share)
2016
Reserves
Replacement
NPV10 (BT)
2P:
 24%
 19%
857%
2,012
1P:
153.2
 26%
 21%
482%
1,011
46.0
 11%
 7%
154%
$16
($millions)
323.9
PDP:
3 Year Average F&D(1)(2)(3)
459
+32% Montney locations
356 2P booked undeveloped future Montney locations
$14.45
$12
$11.08
$9.88
$/boe
Total
Reserves
$7.39
$8
$4
$0
2014
100+ tcfe
TPIIP
27
9.2 tcfe
Risked best estimate ECR
$9.15
$8.38
2015
1P F&D
(1)
(2)
(3)
2016
2P F&D
All F&D and FD&A figures include change in future development capital.
See Appendix for definitions and methodology for calculation of F&D and FD&A.
2016 numbers calculated using unaudited financial and operating information.
$200MM 2017 BUDGET & GROWTH OUTLOOK
90% Directed to Montney Production Growth & Infrastructure Expansion
$140MM
Montney Capital by Area
Directed to Montney drill, complete,
equip & tie-in activities
Tower
$12.5MM
~1.5x debt / FFO
Forecast YE 2017 net debt to Q4 ‘17
annualized funds from operations
28
28,000
Septimus
$24MM
+40% Montneygrowth
Q4 ‘16 to Q4 ‘17 forecast
exit production
Montney Production (BOE/D)
+40%
21,000
14,000
Groundbirch
$11MM
W. Septimus
$135MM
7,000
Q4 '15
Q4 '16
Q4 '17
Forecast
NE BC MONTNEY RESOURCE EVALUATION
Conventional Natural Gas Resource Categories
Reserves and Risked and Unrisked Economic Contingent
Resource (1)(2)(3)(6)(7)(8)
Dec. 31,
2016
Dec. 31,
2015
Tcf
Tcf
%
64.3
35.2
29.1
64.3
35.2
29.1
0%
0%
0%
(1)(2)(3)(4) )(5)(6)
Total Petroleum Initially In Place (TPIIP)
Discovered Petroleum Initially In Place (DPIIP)
Undiscovered Petroleum Initially In Place (UPIIP)
(1) TPIIP, DPIIP and UPIIP have been estimated using a one percent porosity cut-off in the Resource Evaluation, which means that
essentially all gas bearing rock has been incorporated into the calculations.
(2) All volumes in table are Company gross and raw gas volumes.
(3) Sproule’s analysis identified four intervals in the Montney consisting of one interval in the Upper Montney and three intervals in the
Lower Montney.
(4) Crew’s acreage was divided into five (5) areas in the “gas window”.
(5) There is uncertainty that it will be commercially viable to produce any portion of the resources.
(6) There is no certainty that any portion the resources will be discovered. If discovered, there is no certainty that it will be commercially
viable to produce any portion of the resources.
Light & Medium Crude Oil Resource
Categories (1)(2)(3)(4)(5)(6)(7)
Total Petroleum Initially In Place (TPIIP)
Discovered Petroleum Initially In Place (DPIIP)
Undiscovered Petroleum Initially In Place (UPIIP)
Dec. 31, 2016
Dec. 31, 2015
Mmbbls
Mmbbls
%
7,979
1,647
6,332
7,895
1,613
6,282
1%
2%
1%
(1) TPIIP, DPIIP and UPIIP have been estimated using a one percent porosity cut-off in the Resource Evaluation, which means that
essentially all oil bearing rock has been incorporated into the calculations.
(2) All volumes in table are Company gross.
(3) The oil volumes are quoted as Stock Tank Barrels (“STB”).
(4) Sproule’s analysis identified four intervals in the Montney consisting of one interval in the Upper Montney and three intervals in the
Lower Montney.
(5) Crew’s acreage was divided into five (5) areas in the “oil window”.
(6) There is uncertainty that it will be commercially viable to produce any portion of the resources.
(7) There is no certainty that any portion the resources will be discovered. If discovered, there is no certainty that it will be commercially
viable to produce any portion of the resources.
29
Conventional Natural Gas (Bcf)
Reserves(3)
Development Pending ECR
Development on Hold ECR
Natural Gas Liquids (mmbbls)
Reserves (3)
Development Pending ECR
Development on Hold ECR
Chance of
Development
Best Estimate
Unrisked
Best Estimate
Risked
100%
87%
85%
1,426
8,388
500
1,426
7,298
425
100%
88%
84%
59
240
19
59
211
16
100%
89%
80%
12
19
5
12
17
4
(4)(5)
Light & Medium Crude Oil (mmbbls)
Reserves (3)
Development Pending ECR
Development on Hold ECR
(1) All DPIIP other than cumulative production, reserves, and ECR has been categorized as unrecoverable at this time. A portion of the Unrecoverable DPIIP may in
the future be determined to be recoverable and reclassified as contingent resources or reserves as additional technical studies are performed, commercial
circumstances change or technological developments occur; the remaining portion may never be recovered due to the physical/chemical constraints represented
by subsurface interaction of fluids and reservoir rocks.
(2) All volumes in table are company gross and sales volumes. Reserves and development pending volumes include economic cutoff.
(3) For reserves, the volumes are proved plus probable reserves as at December 31, 2016.
(4) The liquid yields are based on average yield over the producing life of the property.
(5) Liquid yields are unique to each area. They are estimated based on gas composition of gas samples in the area and expected plant recoveries.
(6) There is no certainty that it will be commercially viable to produce any of the resources.
(7) All ECR are risked for the chance of development. For ECR, the chance of development is defined as the probability of a project being commercially viable. In
quantifying the chance of development, contingencies that were assessed quantitatively to be less than one in the risking calculation included evaluation drilling,
corporate commitment and timing of production and development. The chance of development is multiplied by the unrisked resource volume estimate, which
yields the risked volume estimate. As many of these factors have a wide range of uncertainty and are difficult to quantify, the chance of development is an
uncertain value that should be used with caution.
(8) The economic status of the ‘development not viable’ project maturity subclass is deemed to be undetermined and is therefore not included in the ECR reported,
representing, on a risked basis, 125 bcf of conventional natural gas, 2 mmbbls of NGLs and 3 mmbbls of light and medium crude oil.
NE BC MONTNEY RESOURCE EVALUATION, CONTINUED
Prospective Resources
(1)(2)(3)(4)(5)(6)(7)
Conventional Natural Gas (Tcf)
NGL (MMbbl)
Light & Medium Crude Oil (MMbbl)
(1)
(2)
(3)
(4)
(5)
Chance of
Commerciality
Best Estimate
Unrisked
Best Estimate
Risked
66%
66%
66%
10,311
327
149
6,774
215
98
All UPIIP other than prospective resources has been categorized as unrecoverable at this time.
All volumes in table are company gross and sales volumes.
The liquid yields are based on average yield over the producing life of the property.
Liquid yields are unique to each area. They are estimated based on gas composition of gas samples in the area and expected plant recoveries.
There is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any of
the resources.
(6) Prospective resources are risked for the chance of discovery and the chance of development. For prospective resources, the chance of development multiplied
by the chance of discovery is defined as the probability of a project being commercially viable. In quantifying the chance of commerciality, factors that were
assessed quantitatively to be less than one in the risking calculation included evaluation drilling, corporate commitment and timing of production and
development, along with the overall chance of discovery. The chance of commerciality is multiplied by the unrisked prospective resource volume estimate, which
yields the risked volume estimate. As many of these factors have a wide range of uncertainty and are difficult to quantify, the chance of commerciality is an
uncertain value that should be used with caution.
(7) All prospective resources are subclassified as either the ‘prospect’ or ‘lead’ project maturity subclass.
30
DEFINITIONS OF OIL & GAS RESOURCES AND RESERVES
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 classified according to the degree of certainty
associated with the estimates as follows:
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.
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.
Cumulative Production is the cumulative quantity of petroleum that has been recovered at a given date.
Resources encompasses all petroleum quantities that originally existed on or within the earth's crust in naturally occurring accumulations, including Discovered and Undiscovered (recoverable and unrecoverable) plus
quantities already produced. "Total resources" is equivalent to "Total Petroleum Initially-In-Place". Resources are classified in the following categories:
Total Petroleum Initially-In-Place ("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.
Discovered Petroleum Initially-In-Place ("DPIIP") is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of discovered
petroleum initially in place includes production, reserves, and contingent resources; the remainder is unrecoverable.
Contingent Resources are 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 such factors 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.
Economic Contingent Resources ("ECR") are those Contingent Resources which are currently economically recoverable.
Project Maturity Subclass Development Pending is defined as a contingent resource that has been assigned a high chance of development and the resolution of final conditions for development are being actively
pursued.
Project Maturity Subclass Development On Hold is defined as a contingent resource that has been assigned a reasonable chance of development, but there are major non‐technical contingencies to be resolved that
are usually beyond the control of the operator.
Project Maturity Subclass Development Unclarified is defined as a contingent resource that requires further appraisal to clarify the potential for development and has been assigned a lower chance of development
until contingencies can be clearly defined.
Project Maturity Subclass Development not Viable is defined as a contingent resource where no further data acquisition or evaluation is currently planned and hence there is a low chance of development.
Undiscovered Petroleum Initially-In-Place ("UPIIP") is that quantity of petroleum that is estimated, on a given date, to be contained in accumulations yet to be discovered. The recoverable portion of undiscovered
petroleum initially in place is referred to as "prospective resources" and the remainder as "unrecoverable."
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.
Unrecoverable is that portion of DPIIP and UPIIP quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may become recoverable in the
future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to the physical/chemical constraints represented by subsurface interaction of fluids
and reservoir rocks.
Uncertainty Ranges are described by the Canadian Oil and Gas Evaluation Handbook as low, best, and high estimates for reserves and resources. The Best Estimate is considered to be the best estimate of the
quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50
percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate.
31
INFORMATION ON RESERVES, RESOURCES & OPERATIONAL INFORMATION
General - All amounts in this presentation are stated in Canadian dollars unless otherwise specified. Throughout this presentation, the terms Boe (barrels of oil equivalent), Mmboe (millions of barrels of oil equivalent), and
Tcfe (trillion cubic feet of gas equivalent) are used. Such terms when used in isolation, may be misleading. In accordance with Canadian practice, production volumes and revenues are reported on a company gross basis,
before deduction of Crown and other royalties and without including any royalty interest, unless otherwise stated. Unless otherwise specified, all reserves volumes in this news release (and all information derived therefrom)
are based on "company gross reserves" using forecast prices and costs. Our oil and gas reserves statement for the year-ended December 31, 2015 includes complete disclosure of our oil and gas reserves and other oil
and gas information in accordance with NI 51-101, and is contained within our Annual Information Form which is available on our SEDAR profile at www.sedar.com. The recovery and reserve estimates contained herein are
estimates only and there is no guarantee that the estimated reserves will be recovered. In relation to the disclosure of estimates for individual properties, such estimates may not reflect the same confidence level as
estimates of reserves and future net revenue for all properties, due to the effects of aggregation. The Company's belief that it will establish additional reserves over time with conversion of probable undeveloped reserves
into proved reserves is a forward-looking statement and is based on certain assumptions and is subject to certain risks, as discussed previously under the heading "Forward-Looking Information and Statements".
Unaudited financial information - Certain financial and operating information included in this presentation for the quarter and year ended December 31, 2016 are based on estimated unaudited financial results for the
quarter and year then ended, and are subject to the same limitations as discussed previously under Forward Looking Information. These estimated amounts may change upon the completion of audited financial statements
for the year ended December 31, 2016 and changes could be material.
Oil & Gas Metrics - This presentation contains metrics commonly used in the oil and natural gas industry, such as "recycle ratio", "finding and development costs", "finding and development recycle ratio", "finding,
development and acquisition costs", "operating netbacks", “reserves replacement” and “IRR”. These terms do not have standardized meanings or standardized methods of calculation and therefore may not be comparable
to similar measures presented by other companies, and therefore should not be used to make such comparisons. Management uses oil and gas metrics for its own performance measurements and to provide shareholders
with measures to compare Crew's operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this presentation, should not be unduly
relied upon. The following oil and gas metrics have the following meanings as used in this presentation:
F&D and FD&A costs - The calculation of F&D and FD&A costs incorporates the change in FDC required to bring proved undeveloped and developed reserves into production. In all cases, the F&D or FD&A number is
calculated by dividing the identified capital expenditures by the applicable reserves additions after changes in FDC costs. Both F&D and FD&A costs take into account reserves revisions during the year on a per boe
basis. The aggregate of the costs incurred in the financial year and changes during that year in estimated FDC may not reflect total F&D costs related to reserves additions for that year. Finding and development costs
both including and excluding acquisitions and dispositions have been presented in this presentation because acquisitions and dispositions can have a significant impact on our ongoing reserves replacement costs and
excluding these amounts could result in an inaccurate portrayal of our cost structure.
Recycle ratio - defined as operating netback per boe divided by F&D or FD&A costs on a per boe basis. Operating netback is calculated as revenue (including realized hedging gains and losses) minus royalties,
operating expenses, and transportation expenses.
Reserves Replacement Ratio - calculated as total reserve additions (including acquisitions net of dispositions) divided by annual production. Crew’s 2016 estimated annual production averaged 22,844 boe/d.
Type Wells - The Septimus and West Septimus type wells presented in slides 11 and 15 herein reflect the average per well proved plus probable undeveloped raw gas assignments (EUR) for Crew's area of operations, as
derived from the Company's year end independent reserve evaluations prepared in accordance with the definitions and standards contained in the COGE Handbook. The type wells are based upon all Crew producing
wells in the area as well as non-Crew wells determined by the independent evaluator to be analogous for purposes of the reserve assignments. Internal Forecast curves incorporate the most recent data from actual well
results and would only be representative of the specific drilled locations . There is no guarantee that Crew will achieve the estimated or similar results derived therefrom.
Test Results and Initial Production Rates - A pressure transient analysis or well-test interpretation has not been carried out and thus certain of the test results provided herein should be considered to be preliminary until
such analysis or interpretation has been completed. Test results and initial production rates disclosed herein may not necessarily be indicative of long term performance or of ultimate recovery.
BOE equivalent - Barrel of oil equivalents or BOEs 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 that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency
of 6:1, utilizing a 6:1 conversion basis may be misleading as an indication of value.
Resource estimates within this Presentation are based upon the independent resource evaluation prepared in accordance with COGE by Sproule Associates Limited effective December 31, 2014 and December 31, 2015,
as indicated.
32
INFORMATION ON RESERVES, RESOURCES & OPERATIONAL INFORMATION
This presentation contains references to estimates of oil and gas classified as TPIIP, DPIIP, UPIIP and ECR in the Montney region in NE BC which are not, and should not be confused with, oil and gas reserves. See
"Definitions of Oil and Gas Resources and Reserves". TPIIP, DPIIP and UPIIP have been estimated in 2015 using a one percent porosity cutoff.
Projects have not been defined to develop the resources in the Evaluated Areas as at the evaluation date. Such projects, in the case of the Montney resource development, have historically been developed sequentially
over a number of drilling seasons and are subject to annual budget constraints, Crew's policy of orderly development on a staged basis, the timing of the growth of third party infrastructure, the short and long-term view of
Crew on oil and gas prices, the results of exploration and development activities of Crew and others in the area and possible infrastructure capacity constraints. As with any resource estimates, the evaluation will change
over time as new information becomes available.
Crew's belief that it will establish significant additional reserves over time with the conversion of Prospective Resource into Contingent Resource, Contingent Resource into probable reserves and probable reserves into
proved reserves is a forward looking statement and is based on certain assumptions and is subject to certain risks, as discussed below under the heading "Forward Looking Information and Statements". Reference is
made to Crew's press release dated May 5, 2016 for a discussion of the principal risks, uncertainties and contingencies associated with the recovery and development of the Resource estimates presented herein.
33
World-Class
MONTNEY RESOURCE
16+ billion
BOE of TPIIP Resource
+40%
Forecast Montney production growth
34
Q4’ 17 over Q4 ‘16
285,000
Net Acres in the Montney