CORPORATE PRESENTATION November 2014 All amounts in Canadian dollars unless indicated otherwise

CORPORATE PRESENTATION
November 2014
All amounts in Canadian dollars unless indicated otherwise
Advisory Regarding Forward-Looking
Information and Statements
This presentation contains forward-looking statements and forward-looking information within the meaning of applicable securities laws. The use of any of the words “will”, “expects”,
“believe”, “plans”, “potential” and similar expressions are intended to identify forward-looking statements or information. More particularly and without limitation, this presentation
contains forward-looking statements and information concerning: NuVista's future strategy, focus and opportunities; exploration and development program; drilling, testing and
completion plans, the timing thereof and the results therefrom; anticipated inventory of drilling locations and type of wells; estimated liquid yields; anticipated well economics including
drilling, completion and equipping and tie-in costs, anticipated well performance and type curves, estimated netbacks, payouts, recycle ratio and estimated rates of return; plans to
improve infrastructure and supply chain; plans to maintain or reduce debt; NuVista's planned divestiture program; expected future development capital; 2014 guidance with respect to
NuVista's capital expenditure program, the number of wells to be drilled, production, product mix, funds from operations, disposition proceeds, debt and working capital; commodity
pricing and exchange rates and industry conditions. Statements relating to "reserves" and "resources" are also deemed to be forward-looking statements, as they involve the implied
assessment, based on certain estimates and assumptions, that the reserves or resources described exist in the quantities predicted or estimated and that the reserves or resources
can be profitably produced in the future. This presentation also contains test results from various wells. Test results are not necessarily indicative of long-term performance or of
ultimate recovery and variations could be material.
The forward-looking statements and information in this presentation are based on certain key expectations and assumptions made by NuVista, including prevailing commodity prices
and exchange rates; applicable royalty rates and tax laws; future well production rates; reserve and resource volumes; the performance of existing wells; the success obtained in
drilling new wells; the sufficiency of budgeted capital expenditures in carrying out planned activities; the availability and cost of labour and services; debt service requirements and
operating costs and the receipt, in a timely manner, of regulatory and other required approvals. Although NuVista believes that the expectations and assumptions on which such
forward-looking statements and information are based are reasonable, undue reliance should not be placed on the forward-looking statements and information because NuVista can
give no assurance that they will prove to be correct. There is no certainty that NuVista will achieve commercially viable production from its undeveloped lands and prospects.
Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ
materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to the risks associated with the oil and gas industry in general such
as: operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the
uncertainty of reserve estimates; the uncertainty of estimates and projections relating to reserves, production, costs and expenses; health, safety and environmental risks; commodity
price and exchange rate fluctuations; marketing and transportation of petroleum and natural gas and loss of markets; environmental risks; competition; incorrect assessment of
the value of acquisitions; failure to realize the anticipated benefits of acquisitions; ability to access sufficient capital from internal and external sources; stock market volatility; and
changes in legislation, including but not limited to tax laws, royalty rates and environmental regulations.
Management has included the above summary of assumptions and risks related to forward-looking statements in order to provide a more complete perspective on NuVista's future
operations. Readers are cautioned that this information may not be appropriate for other purposes. The foregoing list of factors is not exhaustive. Additional information on these
and other factors that could affect the operations or financial results of NuVista are included in reports on file with applicable securities regulatory authorities and may be accessed
through the SEDAR website (www.sedar.com). The forward-looking statements and information contained in this presentation are made as of the date hereof and NuVista
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 so
required by applicable securities laws.
ADVISORY REGARDING OIL AND GAS INFORMATION
Throughout this presentation the terms Boe (barrels of oil equivalent), MBoe (thousands of barrels of oil equivalent), MMBOE (millions of barrels of oil equivalent),Bcfe (billions of
cubic feet of gas equivalent) and Ttcfe (trillion of cubic feet of gas equivalent). Such terms may be misleading, particularly if used in isolation. The conversion ratio of six thousand
cubic feet per barrel (6 Mcf: 1 Bbl) of natural gas to barrels of oil equivalent and the conversion ratio of 1 barrel per six thousand cubic feet (1 Bbl: 6 Mcf) of barrels of oil to natural
gas equivalent is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that
the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis
may be misleading as an indication of value.
November 2014
1
We have sharpened our Focus…
…Growth Model based on Condensate-Rich Wapiti
Montney
1. Focus of Growth in Wapiti - Montney
2. Strong Economics - condensate-rich natural
gas
WAPITI
3. Early Development Phase - increasing well
data
Grande Prairie
W5
4. Profitable Organic Growth Business Model
– very large and growing inventory of
development locations
Edmonton
Calgary
OYEN
Production (MBoe/d)
30
25
~10%
20
15% - 20%
15
25%
10
TSX Stock Symbol:
Market Capitalization:
Shares Outstanding:
NVA
$1.4 Billion
138 Million
5
0
70% - 75%
28%
50%
27%
2013*
Wapiti Montney
2014E
Wapiti Sweet
2015E
Other
* Pro-forma 2013 Divestitures
November 2014
2
The Alberta Condensate-Rich Montney
… A sweet spot in a "world class" play
1. Scalable/Repeatable
• Deposition on the shelf edge - not
isolated pockets
• Gas charged top to bottom
• Over-pressured – low water saturation
High
Quality
Reservoir
2. Porous and Permeable
• Hydrocarbon filled porosity up to 9%
(typically 4-5%)
• Sand/silt reservoir exhibits much better
permeability
Overpressured
150-200 m thick
3. Condensate-rich
• High liquids and condensate
demonstrated in all our wells to date
Condensate
Rich
4. Thick Formation
• 150 – 200 metres
• Multiple developable layers of resource
November 2014
3
The Alberta Condensate-rich Montney
Surge in activity, new well data, new entrants
• High and growing level of industry activity
Elmworth to Kakwa Montney HZ Activity Update*
• > 500 Montney HZ wells licensed and/or
drilled to date
T71
• Currently industry has 15-20 rigs drilling on
map sheet
T70
T69
• Many recent well licenses: CNRL, Shell and
Apache and ongoing pad development by
NVA, 7 Gen, POU and ECA
T68
Elmworth to Kakwa Production Growth*
250
AVG Daily Gas (mmcf/d)
Producing Well Count
200
T66
150
200
150
100
100
50
50
0
0
Hz Well Count
AVG Daily Gas (mmcf/d)
300
T67
T65
NuVista
Encana
Paramount
Sinopec-Daylight
CNRL
Seven Generations
Shell
Apache
Producing Wells
Licensed or NonProducing
R10 W6 Wells
R9 W6
November 2014
T64
T63
R8 W6
R7 W6
R6 W6
R5 W6
*Excludes southern areas of Alberta Condensate-rich Montney (Resthaven and Simonette). Map is an estimate of Industry Land Positions Compiled from Public Data
R4 W6
R3 W6
4
2014 Business Plan – what we've done
Development, infrastructure, and delineation
 On track to meet annual and Q4 2014 Production Guidance
and Cashflow despite divestiture volumes of 2,200 Boe/d YTD
 Efficient capital program of $310 - $320 million is on track
 Development drilling focused mostly upon Bilbo area
 Delineation and continuation program success
 Significant Reserves and Contingent Resources additions as
announced in August 2014
 Built and started up new Bilbo Compressor Station – on time
on budget
 Started delivery to Keyera Simonette plant with startup of
Wapiti-Simonette pipeline
 Announced record high IP30 well results in Bilbo and Elmworth
blocks
 Commenced pad drilling
... Time to look towards 2015!
November 2014
5
2015 Business Plan
Development, infrastructure, and delineation
Focus on Montney Development Drilling in Bilbo and Elmworth
• 60% of wells in condensate-rich Bilbo area
• 20% in Elmworth
• 20% wells for prudent management of expiries and delineation
Expansion of Midstream Infrastructure – Keyera & SemCAMS
• Keyera Simonette plant expansions
• SemCAMS pipeline loop and compression
New NuVista Elmworth compr. station – start up in Q3 2015
Continue Optimizing D&C Activities
… and Planning continues for future capacity additions 2016+
November 2014
6
NuVista Wapiti Montney
Our activity and landholdings
Increasing Activity
• 23 wells on production (IP30) – ramping
production up through Q4
• 2-3 rigs on average in 2014
• 32 wells on production by end 2014 versus 16
at start of year
Manageable Land Tenure
• NuVista has over 220 gross sections of land
(86% WI)
• Minimal 3rd party encumbrances
• Manageable expiries
NVA Vertical Cored Wells
T 69
NVA In-Progress Wells
Pipestone
Elmworth
Development
Block
Middle
Montney 'C'
Silty
sandstone
120 Metres
Expanding Development Blocks
• Strategic land swaps
• Bilbo Block Expanded from 19 to 21 sections
based on well results
• Elmworth Block expanded from 20 to 23
sections based on well results
• Delineation advancing quickly in Gold Creek
NVA Producing Wells
Middle
Montney 'B'
Silty
sandstone
Industry Middle
Montney HZ’s
1-7 Completed
5-24 New IP30
16-1 Drilled
Gold Creek
11-28 Drilled
16-27 Drilled
1-28 Drilled
80 Metres
Attractive Crown royalty of 5%
• Elmworth for ~3.5 yrs
• Bilbo for ~2.5 yrs
19 Wells On Production
2 Rigs Drilling
Lower
Montney
Shale
R10
W6
R10
W6
November 2014
Bilbo
Development
Block
1-16 Drilled
7
NuVista Wapiti Montney
Third party
planned and
unplanned
downtime and
facility delays
impacted Q2
production
2014 Production
Total Montney Production
16,000
14,000
Boe/d
12,000
10,000
8,000
6,000
4,000
2,000
2011 FY
2012 FY
2013-Q1
2013-Q2
2013-Q3
2013-Q4
Bilbo Development Block
2014-Q1
2014-Q2
2014-Q3
2014-Q4
Elmworth Development Block
12,000
Boe/d
10,000
8,000
Ramp up of Bilbo
compressor
station and startup
of Keyera pipeline
6,000
10,000
8,000
Boe/d
12,000
6,000
4,000
4,000
2,000
2,000
-
November 2014
-
8
Bilbo Development Block
All future locations no more than 1 mile from
existing proven typecurve producers
Liquids Typecurve
• >100* total locations in development area
• Trend of improving liquids yields
Bbls/MMcf
Condensate
8
5
Butane
Propane
Inputs
75
Planning Prices
Upside Prices
Capital
$9MM
$9MM
Raw EUR
4.4 Bcf
4.4 Bcf
<$10.00/boe
<$10.00/boe
38%
38%
330,000
330,000
AECO $/GJ
$3.50
$4.00
WTI Price US$/Bbl
$90.00
$95.00
$10.4MM
$12.4MM
1.2
1.4
1.4 yrs
1.2 yrs
70%
88%
$37.00
$41.00
$8.75/Boe
$8.75/Boe
$15,000/Boe/d
$15,000/Boe/d
Opex
Liquids
Bbls C5+ / well
Economics
NPV10
NVA Montney Producers
Bilbo Development Block
• 16 Wells with IP30
• 3 Additional Wells on-stream
• 2-Rigs Drilling
PIR
Payout
ROR
Netback / Boe
NVA Drilled/Completed
F+D
Montney Horizontal Wells
NVA 3-36 Compressor and connect
to Keyera (startup Q2 2014)
Cap. Eff.
November 2014
*Un-risked assuming 4 wells/zone/section, 80% land utilization
*Pricing and costs inflated at 2% per annum
9
Montney Performance
South Block (Bilbo)
1,800
24
Cumulative-to-Date
Bbls/MMcf
Condensate
Continue to see
strong condensate
yield >75 Bbls/MMcf
1,500
Propane
16
900
600
12
$60
85
2014 YTD September Field Netbacks
$50
Transportation
Royalty
$40
$/Boe
Original two South Block discovery
wells. Step change in curve
demonstrates we have optimized
fracs since then
11
Butane
Producing Well Count
$36.16
$30
Butane/Propane
$10
8
Operating Costs
Condensate
$20
Natural Gas
$0
Revenues
Costs
2013 Field Netback
300
4
0
0
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Month
Typecurve Liquids (boed)
Typecurve Sales Gas (boed)
Avg Liquids (boed)
Avg Production (boed)
November 2014
$60
$/Boe
Production (boe/d)
1,200
20
9
$50
Transportation
$40
Royalty
$30
$31.46
Operating Costs
Condensate
$20
Butane/Propane
$10
Natural Gas
$Revenues
Costs
10
Well Clean-outs
Example of recent success with Coil Tubing Mill-outs
4.4 Bcf Type Curve
Gas Rate (mcf/d)
Tbg (psig)
Csg (psig)
Avg CGR (bbl/MMscf)
18,000
540
Coil tubing mill-out
operation yields
significantly increased gas
rate and pressure
14,000
480
420
12,000
360
10,000
300
8,000
240
6,000
180
4,000
120
2,000
60
0
CGR (bbl/mmscf)
Raw Gas Rate (mcf/d), Pressure (psi)
16,000
0
0
10
20
30
40
50
60
70
80
90
100
Cumulative Gas (MMCF)
November 2014
11
Elmworth Development Block
All future locations no more than 1 mile from
existing proven typecurve producers
• >100 Total locations identified within development area
• Typecurve increased from 4.4 Bcf to 6.0 Bcf
Liquids Typecurve
Bbls/MMcf
Condensate
9
5
Butane
NVA Montney Producers
45
Propane
NVA Drilled / Completed
Inputs
Planning Prices
Upside Prices
Capital
$9MM
$9MM
Raw EUR
6.0 Bcf
6.0 Bcf
~$10.00 /boe
~$10.00 /boe
29%
29%
263,000
263,000
AECO $/GJ
$3.50
$4.00
WTI Price US$/Bbl
$90.00
$95.00
$8.2MM
$10.3MM
0.9
1.2
1.8 yrs
1.5 yrs
51%
67%
$30.00
$33.00
$7.50/Boe
$7.50/Boe
$13,700/Boe/d
$13,700/Boe/d
Montney Horizontal Wells
NVA 7-22 Compressor Site
and Connect to SemCAMS
Opex
Liquids
Elmworth
Development
Block
Bbls C5+ / well
Economics
NPV10
PIR
Payout
New IP30
ROR
Netback / Boe
F+D
Cap. Eff.
•
Unrisked assuming 4 wells/ zone/ section, 80% land utilization
November 2014
*Pricing and costs inflated at 2% per annum
12
Montney Performance
North Block (Elmworth)
4.4 bcf Type Curve
6 bcf Type Curve
First 3 NVA Wells
Last 4 NVA Wells
10,000
Cumulative-to-Date
Bbls/MMcf
9,000
8,000
Butane
$60
6,000
5,000
9
42
Propane
$/Boe
Raw Gas Rate (mcf/d)
7,000
11
Condensate
Increased typecurve to
6 Bcf based on recent
NVA wells due to frac
design and other
industry well data
2014 YTD September Field Netbacks
$50
Transportation
$40
Royalty
$33.64
$30
Condensate
$20
4,000
Operating Costs
Butane/Propane
$10
Natural Gas
$0
Revenues
3,000
Costs
2013 Field Netback
2,000
$60
$/Boe
1,000
$50
Transportation
$40
Royalty
$30
$24.17
Condensate
$20
0
Butane/Propane
$10
Natural Gas
$Data includes only NVA wells – excludes 1st well (9-22)
November 2014
Cumulative Production (MMCF)
Operating Costs
Revenues
Costs
13
R11
Lower Montney Activity
NuVista data collection in progress
Industry Hz well results coming available early 2015
R10
R9
R8
R7
R6
R5
R4
R3
R2
R1W6
•
Pipestone
R26W5
T71
Multiple pilot wells in progress by
industry – No public test results yet
T70
NVA 15-13-68-7W6 Vertical
Over-pressured – 133 bbls/mmcf condy
•
NuVista has Good distribution of
vertical wells and cores
T69
Elmworth
SCL 1-33-67-5W6
Confidential: 7-Jun-2015
•
SCL 17-67-5W6
Confidential: 22-May-2015
•
NuVista Vertical Completion: Over
pressured, Condensate-Rich
T68
Gold Creek
Wapiti
Karr
NuVista Pilot possibly as early as
2015
T67
T66
7Gen 13-24-65-5W6
Rig Released: 24-Dec-2012
South Wapiti
NVA Lands
T65
Bilbo
7Gen 12-32-64-5W6
Confidential:15-Jan-15
Montney Wells
LWR Montney A Wells
LWR Montney Cores
November 2014
T64
Kakwa
7Gen 1-5-63-3W6
Confidential: 19-Feb-15
T63
T62
14
Montney D&C – Drilling
Drilling time and cost reduction continues…
• Brine-based drilling fluids
• Optimizing drill bits
• Further, faster via experimentation & eng.
0
Q1 2013 AND PRIOR
1,000
Measured Depth (m)
• Steady progress reducing drilling times
and drill cost per meter
• Transitioning to drilling longer
horizontal laterals
• Early adopter of new technology
Days versus Depth
2013 WELLS
2014 WELLS
2,000
Steady
progress
reducing
drilling times,
evolving to
longer hz
section
3,000
4,000
5,000
6,000
0
• Measured approach to pad drilling
10
20
30
40
50
60
70
Days from Spud
• ~65 % of wells to be pad-drilled in 2015
($ per Hz Meter Drilled)
9,000
Drilling Costs per Hz Meter Drilled
Trend-Line
8,000
7,000
6,000
5,000
4,000
3,000
2,000
1,000
0
1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35
Wells (Chronological)
November 2014
15
Montney D&C - Completions
Focused on optimizing recovery
Montney IP30 Progress
NuVista's Completion Process
•
Open-hole completion with ball-drop frac
technology
Large volume slickwater fracs
Longer Laterals With More Frac Intervals
•
•
Manage risks of greater lengths and increasing frac
density
Utilizing micro-seismic fracture monitoring
1,500
Boe/d
•
1,250
1,000
2012 & Prior
2013
(5 Wells)
(11 Wells)
2014
(13 Wells)
Water Management Progress
•
Flowback water – purchased disposal well and
drilling multiple in-field source and disposal wells in
2015
•
Water recycling pilots continue to progress
Optimizing Recovery
•
Longer wells, energized fracs, hybrid fracs, frac
intensity, high strength proppants, coil tubing
millouts…..
November 2014
16
Wapiti Montney Egress
Access to mid-stream facilities for short and medium term egress …
… and still more options for the long term
Loop pipeline to existing SemCAMS K3
gas plant; expected startup mid-2015
SemCAMS compressor station on
stream mid-2016
NuVista (50%)
Compressor Station
NuVista (100%) Elmworth
Compressor Station
Raw Gas Capacity – 80 MMcf/d
Condensate Cap'y – 4,800 Bbl/d
Potential for new Wapiti area gas plant
CNRL Gold Creek Plant
NuVista (100%) Bilbo Compr.
Station
Raw Gas Capacity - 80 MMcf/d
Condensate Cap'y– 8,000 Bbl/d
NuVista (100%)
Compressor Station
Keyera
Simonette Plant
Keyera (100%)
Raw Gas Pipeline Capacity – 150 MMcf/d
NuVista Firm Capacity – 80 MMcf/d
CNRL Gold Creek gas plant
Pipeline to Keyera Simonette on stream
Sept 26, 2014 with additional plant
expansion planned for Q1 & Q3 2015
Potential expansion of Keyera Simonette
Gas Plant
Condensate Pipeline Cap'y – 20,000 Bbl/d
SemCAMS K3
Plant
Condensate Pipeline
Gas Pipeline
Online
Under Construction
T58
Planning Stage
R12 W6
November 2014
R1 W6
R18 W5
17
Wapiti Montney Processing Capacity
Firm Capacity and line-of-sight to long term growth
Wapiti Montney Raw Gas Processing Capacity
And Estimated Equivalent Montney Production
New Sour Gas
Plant
45,000
180
Additional Capacity from
Existing Sour Gas Plants
160
30 MMcf/d
40,000
35,000
Raw Gas - MMcf/d
140
30,000
120
30 MMcf/d
25,000
15 MMcf/d
20,000
30 MMcf/d
15,000
100
80
60
10,000
40
35 MMcf/d
5,000
20
0
2013
2014
SemCAMS
November 2014
2015
Keyera
2016
17 MMcf/d
2017
0
Estimated Equivalent Montney Production – Boe/d
200
Min TOP Commitment
18
Driving down costs on all fronts
Total Cash Costs ($/Boe)*
$17
$16
$15
$14
General and Administrative ($/Boe)
$13
$3.50
$12
$3.00
$11
$10
2013
2014E
2015E
$2.50
$2.00
Royalties (%)
$1.50
12%
10%
$1.00
2013
8%
2014E
2015E
6%
4%
2%
0%
2013
November 2014
2014E
2015E
*Includes: Opex, Royalties & Transportation and for Royalties, assumes flat commodity pricing
19
Line-of-Sight to Significant Production and
Cash Flow Growth
Capital Expenditures ($MM)
Production (MBoe/d)
$750
60
Accelerated Case
Base Case
Accelerated Case
Base Case
50
$600
40
$450
30
$300
20
$150
10
0
$0
2014E
2015E
2016E
2017E
2015E
2016E
2017E
2018E
2017E
2018E
Debt-Q4 Annualized Cashflow*
Cashflow* ($MM)
$600
2014E
2018E
Accelerated Case
2.0x
Base Case
$500
1.5x
$400
1.0x
$300
$200
0.5x
$100
2014E
*Assumptions:
Base Case
0.0x
$0
2015E
2016E
2017E
2018E
2014E
2015E
2016E
2015 US$80/bbl WTI; C$3.60/GJ AECO; 1.14:1.00 C$:USD
2016+ US$85/bbl WTI; C$3.50/GJ AECO; 1.05:1.00 C$:USD
Costs and Prices are inflated at 2% per annum
November 2014
20
NuVista 2014 & 2015 Guidance
GUIDANCE - 2014
Production Guidance
(Boe/d)
Actual Production
(Boe/d)
Full Year
17,750 - 18,500
On track
Q4
21,000 – 22,500
On track
Q3
17,300 – 18,300
18,030
Q2
13,000 – 14,000
14,493
Q1
n/a
17,823
Capital
$310 - $320 million
Funds from Operations:
$110 - $120 million
GUIDANCE - 2015
November 2014
FY Capital:
$340 - $380 million
FY Production:
23,500 – 25,000 Boe/d
Funds from Operations:
$180 - $200 million
21
NuVista: Looking Forward
The corner has been turned … Now we grow
 Focused, repeatable and profitable
 Costs falling, condensate production rising, completions
improving
 Two project development areas define certainty
 Long-term gas processing and liquids egress secured
 Contingent resource and reserves reports confirm upside
 Solid balance sheet & evergreen non-core divest program ongoing
We have the Assets We have the Will
We have the Team
We have the Strategy… To Deliver
November 2014
22
APPENDIX
November 2014
23
The Montney - A "World Class" Play
… EURs and investment growing, capital
efficiency improving, and sub plays expanding
Why is the Montney Getting Better?
1. The Scale – stretching from NE BC into AB, difficult to
find an analogue commercial development of this
scale
2. The Rock - dolomitic siltstones (rarely shales) and
very fine grained sandstones
3. The Resource Density – massively thick formation
supports multi-horizon development
4. The Reservoir – reservoir augmented by stimulation
yielding better recoveries than other tight gas/liquids
resources
Montney Rock Type
Siltstone
Siltstone and some sandstone
Siltstone, sandstone and some
dolostone
What's Happening with the Play?
• Increased capital investment advancing the play
from both an appraisal and development perspective
450
Miles
• Technological advancement will continue to improve
supply costs
• Core areas within the Montney will rival any tight
gas/liquids resource play in North America
November 2014
Source: National Energy Board (used with permission)
24
The Montney - A "World Class" Play
Competitive with US plays and increasing activity
 Massive Thickness: Montney is akin to stacking four
separate shale plays on top of one another
 Lithology and Fracability: Low clay content, low
Poisson’s Ratio and high Young’s Modulus all contribute
to the Montney having a greater propensity to be
hydraulically fractured
 High Permeability: natural fluid flow present because it
is dominated by siltstone sized particles
 Higher Recovery Factors: recoverable gas volumes
from pure shale plays are generally low (20% range),
while the Montney is estimated to recover closer to 50%
Reservoir Attribute
All Montney
Cumulative Wells Drilled
3,500
3,000
2,500
2,000
1,500
1,000
500
0
2007 2008 2009 2010 2011 2012 2013 2014
Q1
Montney
Haynesville
Marcellus
Eagle Ford
Barnett
Up to 300
40 - 110
25 - 90
15 - 85
25 - 180
2-10 / 10,000100,000
5 – 12 / <100
5 – 13 / 20 – 55
4 – 12 / 50 – 1200
3 – 9 / 250
88 – 90
(20 – 25% total carb
– only 5% calcite)
45 – 65
(24% Carb)
60 – 80
(15% Carb)
75 – 85
(51% Carb)
70 – 90
(13% Carb)
0.18 – 0.22
0.21 – 0.25
0.18 – 0.27
0.20 – 0.22
0.15 – 0.29
50 – 60
27.6 – 37.9
22.1 – 26.9
27.6 – 34.5
34.5 – 48.3
Original Gas in Place (OGIP Bcf / sec)
150 – 280
125 – 300
20 – 100
80 – 170
100 – 210
EUR (Bcf / well)
4.0 – 15.0
4.0 – 7.5
2.0 – 6.0
3.0 – 8.0
1.5 – 4.5
Gross Thickness (metres)
Porosity (%) / Permeability (nD)
Mineralogy (% Non-Clay)
Poisson’s Ratio
Young’s Modulus (GPa)
Source: RBC Rundle, Street research. DUG Canada, Chalmers et al., Hammes, et. Al., 2011
November 2014
25
Commodity Price Risk Management
WTI Oil – we are well hedged
Crude Oil Hedge Position
4,000
100.00
98.00
3,500
3,000
94.00
2,500
92.00
2,000
90.00
88.00
1,500
Floor C$ WTI price of $95.96/Bbl on ~59% of
Q4 2014 net production
1,000
86.00
84.00
Floor C$ WTI price of $97.89/Bbl on ~40% of
2015 net production
500
Price, C$/Bbl
Hedged Volume, Bbl/d
96.00
82.00
80.00
2014 Q4
2015 Q1
Bbl/d Capped
November 2014
2015 Q2
2015 Q3
2015 Q4
Bbl/d Uncapped
2016 Q1
2016 Q2
Avg. Floor
2016 Q3
2016 Q4
Avg. Ceiling
26
Commodity Price Risk Management
AECO natural gas – hedging in good shape
100,000
4.50
90,000
4.00
80,000
3.50
70,000
3.00
60,000
2.50
50,000
2.00
40,000
30,000
20,000
10,000
Floor AECO price of ~$3.69/Mcf* on ~60% of
Q4 2014 net production
Price, C$/GJ
Hedged Volume, GJ/d
Natural Gas Hedge Position
1.50
1.00
Floor AECO price of ~$3.87/Mcf* on ~54% of
2015 net production
0.50
0
0.00
2014 Q4
GJ/d Capped
2015 Q1
2015 Q2
2015 Q3
GJ/d Uncapped
2015 Q4
2016 Q1
2016 Q2
GJ/d AECO-NYMEX Basis
2016 Q3
2016 Q4
Avg. Floor
Avg. Ceiling
* - Includes some NYMEX translated to AECO equivalent price hence can change slightly with Fx
November 2014
27
Operating and Financial Results
Understanding the financial power of the Montney
Corporate Cash Flow
Corporate Cash Flow Netback
$35
$25
$31
$30
$27
$23
$22
$16.47
$19
$20
$15
$19.26
$20
$/Boe
$ Million
$25
$15
$12
$15
$11.72
$10
$13.59 $12.99
$11.42
$8.67
$10
$5
$5
$Q1
2013
Q2
2013
Q3
2013
Q4
2013
Q1
2014
Q2
2014
$-
Q3
2014
Q1
2013
$50
$45
$40
$35
$30
$25
$20
$15
$10
$5
$-
$28.12
$16.53
Properties Total
November 2014
$12.31
Wapiti
Montney
Other
Properties
Q3
2013
Q4
2013
Q1
2014
Q2
2014
Q3
2014
YTD 2014 September Field Netbacks
$/Boe
$/Boe
2013 Annual Field Netbacks
Q2
2013
$50
$45
$40
$35
$30
$25
$20
$15
$10
$5
$-
$35.14
$21.57
$11.06
Properties Total
Wapiti
Montney
Other
Properties
28
Condensate Pricing
Strong demand and premium price for
the long term
Crude and Condensate Prices
WTI
Edm Par
May-14
Mar-14
Jan-14
Nov-13
Sep-13
Jul-13
May-13
Mar-13
Jan-13
Nov-12
Sep-12
Jul-12
May-12
Mar-12
• US condensate supply is increasing but
condensate splitters are being built; and
some discussion that condensate export
restrictions may be reconsidered
Jan-12
• Condensate in Alberta is typically priced
at a premium to C$ WTI and Edm Par
crude oil
$130
$120
$110
$100
$90
$80
$70
$60
$50
$40
$30
Price, C$/Bbl
• Condensate is used in Alberta as a
diluent to ship heavy oil on pipelines
Condensate
Western Canada Condensate Supply and Demand
• Condensate must be transported to
Alberta – "we're on the right end of the
pipe"
• Premium for condensate will always
reflect the cost of transportation to
deliver to Alberta while demand outstrips
local Alberta production … and it does
November 2014
29
Advancing the Wapiti Montney Plan
The track record to date
2011
2012
2013
2014YTD
1
5
16
23
Rigs Drilling
0-1
1-2
2-3
3
Annual Production
(Boe/d)
281
1,265
4,650
7,325
TP+PA Reserves*
(MMBoe)
12
29
86
136
0
200
(252 gross
locations)
425
(577 gross
locations)
477
(670 gross
locations)
164 Gross
151 Net
192 Gross
176 Net
197+ Gross
179 Net
~220 Gross
~190 Net
NVA Producing
Horizontal Wells
(Cumulative)
Best Estimate
Contingent
Resource* (MMBoe)
Montney Land
Position (Sections)
* See Appendix for disclosures regarding Reserves and Resources
November 2014
30
Montney IP30's
Well
IP30*
Raw Gas
(MMcf/d)
Cumulative to date (Oct 20, 2014)
Condensate
(Bbls/d)
Total Sales
(Boe/d)
CGR Bbl/MMcf
Days on Prod.
(raw/C5+)
CGR
Bbls/MMcf
(raw/C5+)
Condensate
(MBbls)
Cumulative
Sales Gas
(MMcf)
Total
(Mboe)
Current Delineation Typecurve
5.8
261
1,217
45
Ultimate
45
198
3,850
923
Current Elmworth (North) Dev. Typecurve
7.4
333
1,559
45
Ultimate
45
384
5,250
1,259
Current Bilbo (South) Dev. Typecurve
5.8
435
1,356
75
Ultimate
75
330
3,850
1,029
Well 1 (09-22 - North)
5.5
232
1,003
42
1,044
34
44
1,136
252
Well 2 (02-01- South)
4.4
231
923
52
693
38
47
1,126
244
Well 3 (16-21 - North)
7.3
379
1,445
52
620
37
58
1,274
297
Well 4 (08-15 - North)
3.9
280
909
72
646
73
61
682
191
Well 5 (02-09 - North)
7.8
356
1,601
46
605
48
70
1,273
315
Well 6 (05-33 - Central)
3.3
245
729
75
480
57
34
547
130
Well 7 (14-04 - North)
6.7
347
1,480
52
479
38
53
1,220
284
Well 8 (15-22 - South)
3.4
390
918
116
323
91
54
507
152
Well 9 (15-07 - South)
7.2
935
2,003
129
344
109
141
1,075
350
Well 10 (13-03 - North)
5.0
266
1,074
53
392
49
53
912
227
Well 11 (13-11 - South)
5.2
664
1,494
128
406
91
84
797
241
Well 12 (08-05 - North)
2.7
231
662
87
316
78
32
353
99
Well 13 (13-02 - South)
5.1
545
1,413
107
287
79
54
606
166
Well 14 (05-26 - South)
5.1
394
1,312
77
280
79
54
606
166
Well 15 (13-07 - South)
4.2
595
1,241
142
152
143
57
307
116
Well 16 (15-28 - North)
10.2
396
2,092
39
288
30
50
1,379
314
Well 17 (14-22 - South)
7.9
790
2,265
100
173
95
87
796
243
Well 18 (15-17 - North)
6.1
218
1,210
36
48
40
10
205
49
Well 19 (16-19 - Central)
6.8
382
1,312
56
134
53
28
434
109
Well 20 (13-25 - Northeast)
1.8
258
537
143
122
137
24
152
50
November 2014
*Excludes non-producing days. Well 13 and Well 14 are post-intervention
31
Montney IP30's
Well
IP30*
Raw Gas
(MMcf/d)
Cumulative to date (Oct 20, 2014)
Condensate
(Bbls/d)
Total Sales
(Boe/d)
CGR Bbl/MMcf
Days on Prod.
(raw/C5+)
CGR
Bbls/MMcf
(raw/C5+)
Condensate
(MBbls)
Cumulative
Sales Gas
(MMcf)
Total
(Mboe)
Current Delineation Typecurve
5.8
261
1,217
45
Ultimate
45
198
3,850
923
Current Elmworth (North) Dev. Typecurve
7.4
333
1,559
45
Ultimate
45
384
5,250
1,259
Current Bilbo (South) Dev. Typecurve
5.8
435
1,356
75
Ultimate
75
330
3,850
1,029
Well 21 (04-05 - South Pad #3)
9.8
512
2,069
52
74
55
30
481
114
Well 22 (07-06 - South-Pad #2)
4.3
405
1,077
93
173
91
22
200
59
Well 23 (08-06 - South Pad #2)
4.6
712
1,379
156
83
150
40
201
80
Well 24 (04-27 - South Pad #3)
7.8
611
1,760
78
78
77
35
381
103
Well 25 (16-33 - South Pad #4)
4.9
331
1,087
67
43
62
13
179
46
Well 26 (14-34 - South Pad #4)
4.2
268
916
64
39
63
9
123
32
Well 27 (04-02 - South Pad #5)
8.3
512
1,740
61
44
62
20
262
69
Well 28 (05-02 - South Pad #5)
7.9
578
1,770
74
55
65
29
363
97
Well 29 (05-24 - North)
9.0
236
1,694
26
34
26
7
252
54
November 2014
*Excludes non-producing days.
32
Montney IP30's
… Improving annually
Well
IP30*
Raw Gas
(MMcf/d)
Cumulative to date (Oct 20, 2014)
Condensate
(Bbls/d)
Total Sales
(Boe/d)
CGR Bbl/MMcf
Days on Prod.
(raw/C5+)
CGR
Bbls/MMcf
(raw/C5+)
Condensate
(MBbls)
Cumulative
Sales Gas
(MMcf)
Total
(Mboe)
Current Delineation Typecurve
5.8
261
1,217
45
Ultimate
45
198
3,850
923
Current Elmworth (North) Dev. Typecurve
7.4
333
1,559
45
Ultimate
45
384
5,250
1,259
Current Bilbo (South) Dev. Typecurve
5.8
435
1,356
75
Ultimate
75
330
3,850
1,029
2012 & Prior Average (5 Wells)
5.8
296
1,176
53
2013 Average (11 Wells)
5.3
455
1,311
91
Well 17 (14-22 - South)
7.9
790
2,265
100
173
95
87
796
243
Well 18 (15-17 - North)
6.1
218
1,210
36
48
40
10
205
49
Well 19 (16-19 - Central)
6.8
382
1,312
56
134
53
28
434
109
Well 20 (13-25 - Northeast)
1.8
258
537
143
122
137
24
152
50
Well 21 (04-05 - South Pad #3)
9.8
512
2,069
52
74
55
30
481
114
Well 22 (07-06 - South-Pad #2)
4.3
405
1,077
93
173
91
22
200
59
Well 23 (08-06 - South Pad #2)
4.6
712
1,379
156
83
150
40
201
80
Well 24 (04-27 - South Pad #3)
7.8
611
1,760
78
78
77
35
381
103
Well 25 (16-33 - South Pad #4)
4.9
331
1,087
67
43
62
13
179
46
Well 26 (14-34 - South Pad #4)
4.2
268
916
64
39
63
9
123
32
Well 27 (04-02 - South Pad #5)
8.3
512
1,740
61
44
62
20
262
69
Well 28 (05-02 - South Pad #5)
7.9
578
1,770
74
55
65
29
363
97
Well 29 (05-24 - North)
9.0
236
1,694
26
34
26
7
252
54
2014 Average (13 wells)
6.4
447
1,447
77
November 2014
*Excludes non-producing days.
33
Focus on Wapiti
Our lands contain the Montney with the bonus
of significant Deep Basin uphole potential
Acres 000's
Dunvegan
Falher
Cadomin
Nikanassin
CARDIUM
MONTNEY
FAIRWAY
Gross
79
81
88
96
Net
44
38
47
80
DUNVEGAN
CADOTTE
NOTIKEWIN
WAPITI
FALHER
BLUESKY
GETHING
CADOMIN
NIKANASSIN A
NIKANASSIN C
Wapiti Uphole Zones
7,000
Liquids
Natural Gas
Wapiti Montney has a younger brother:
The Montney is overlain by over 1.5 km high x
100,000 NVA acres of high potential wet gas and
oil Jurassic/Cretaceous deep basin formations
November 2014
Production (Boe/d)
6,000
MIDDLE MONTNEY
LOWER MONTNEY
5,000
4,000
3,000
2,000
1,000
0
34
North Elmworth Land Acquisition
"Strong addition to the family" Announced August 2014
Recently
Acquired
NVA Block
•
Acquired 12.5 Gross (12.0 net) sections of
Montney Rights for $35MM - $4,560/acre
•
Increases NVA Montney position to over
220 gross sections (194 net)
•
3 Potentially developable layers within the
Middle Montney + Lower Montney Upside
•
Block is contiguous and located
immediately adjacent to strong and proven
wells
•
Excellent reservoir and liquids potential
leverages our Montney learnings to date
•
Creates opportunity for development into
additional egress options
•
Contingent Resource/Reserves Evaluation
in-progress
•
Up to 2 wells planned for 2015
Pipestone
Elmworth
Gold Creek
Wapiti
Karr
South Wapiti
Bilbo
Kakwa
NVA Lands
Montney Wells
November 2014
35
Contingent Resource and Reserves
Significant delineation of resource and
conversion to reserves in 2014
Middle Montney 'C'
Middle Montney 'B'
*DPIIP: 115 Sections – 51% of Current Gross Sections
Best Estimate Contingent Resource – 312 Locations (Gross)
Proved plus Probable Reserves: (23.5 Sections Gross) 66 Locations (Gross)
*DPIIP: 140 Sections – 63% of Current Gross Sections
Best Estimate Contingent Resource – 358 Locations (Gross)
Proved plus Probable Reserves: (38 Sections Gross) 108 Locations (Gross)
See Appendix
for important
disclosures
regarding
Reserves and
Resources
Montney 'C' CR
Montney 'B' CR
Montney 'C'/'B'
2P Reserves
17% of Gross
Acreage Assigned
Proved plus
Probable Reserves
10% of Gross
Acreage Assigned
Proved plus
Probable Reserves
Pipestone
120 Metres
D
Middle
C
Montney
North
Central
South
2015Drill
80 Metres
B
November 2014
Lower
Montney
Future Pilot Well
No wells yet but significant future potential
*Discovered Petroleum Initially in-place: Area includes lands assigned Economic Contingent Resource or Proved plus Probable Reserves
36
Resources & Reserves Rising Fast
Independent Study Updated as of August 2014*
Discovered Petroleum Initially-In-Place(1)
Cumulative Production(2)
0.02 Tcfe
Reserves (Proved Plus Probable)(2)(3)
0.81Tcfe
Economic Contingent Resource (Best Estimate)(4)(5)
2.86 Tcfe
DPIIP (Best Estimate)(7)
700
844
295
577
120,000
400
300
477
229
425
200
252
43
2012
TP+PA Reserves
174
121
100
0
2013
Aug. '14
Best Est. CR
140,000
511
500
670
Acreage Assigned Contingent Resource
So Far…
613
600
698
MM Boe
900
800
700
600
500
400
300
200
100
0
Reserves + Contingent Resource
200
29
86
136
2012
2013
Aug. '14
TP+PA Reserves
Gross Acres
Gross Well Count Now 844
8.13 Tcf
100,000
80,000
60,000
40,000
20,000
Montney C
Best Est. CR
Montney B
Lower
Montney
* See Appendix for important disclosures regarding Reserves and Resources.
Note: 45 wells moved out of Contingent Resource into Proved plus Probable, and 63 Contingent Resource wells added
November 2014
37
2014 July Reserves Report
Montney Transition in full-swing
…..growth proven to be continuing
2014 Mid-year Reserves Report – GLJ Petroleum Consultants Ltd.
•
Montney DPIIP increased by 40%
•
Montney 2P reserves volume increased by 57%
•
Montney 2P F&D of $11.79/Boe - YTD Netback $38.53/boe - Recycle Ratio 3.3x
•
Corporate 2P reserves volume increased by 33%
•
Corporate 2PBT NPV10% increased 43% to $1.9 billion
•
Corporate 2P FDC of $1.4 billion (~5x 2014 forecast capex)
Corporate 2P Reserves (MMBoe)
200
186
180
50
140
1,898
507
1,600
18%
1,400
120
1,200
53
100
800
136
65
98
86
40
20
2012
Other
612
35%
847
200
0
2011
5%
1,392
1,197
400
29
12
600
42%
476
1,000
80
0
2,000
Corporate 2P Reserves by Category
1,800
160
60
Corporate 2P NPV10% ($MM)
2013
Wapiti Montney
Aug. '14
87
2011
Other
167
2012
2013
Wapiti Montney
Aug. '14
PDP
PDNP
PUD
PAUD
* See Appendix for important disclosures regarding Reserves and Resources
November 2014
38
Advisory Regarding Reserves and
Resource Disclosure
RESERVES AND RESOURCE DISCLOSURE
The reserves and resources estimates prepared herein have been evaluated by an independent qualified reserves evaluator in accordance with NI 51-101
and the COGE Handbook. The reserves and resources have been categorized accordance with the reserves and resource definitions as set out in the COGE
Handbook, which are set out below:
Discovered petroleum initially-in-place or 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 Cumulative Production, Reserves, and Contingent Resources;
the remainder is categorized as unrecoverable.
Cumulative Production is the cumulative quantity of petroleum that has been recovered at a given date.
Reserves are estimated remaining quantities of petroleum anticipated to be recoverable from known accumulations, as of a given date, based on the
analysis of drilling, geological, geophysical, and engineering data; the use of established technology; and specified economic conditions, which are generally
accepted as being reasonable. Reserves are further classified according to the level of certainty associated with the estimates and may be sub-classified
based on development and production status.
Proved Reserves are those quantities of petroleum, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to
be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government
regulations.
Probable Reserves are those additional quantities of petroleum that are less certain to be recovered than Proved Reserves, but which, together with Proved
Reserves, are as likely as not to be recovered.
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.
There is no certainty that it will be commercially viable to produce any portion of the Contingent Resources or that any portion of the volumes currently
classified as Contingent Resources will be produced. The recovery and resource estimates provided herein are estimates. Actual Contingent Resources (and
any volumes that may be classified as Reserves) and future production from such Contingent Resources may be greater than or less than the estimates
provided herein.
Economic Contingent Resources (“ECR”) are those Contingent Resources that are currently economically recoverable based on specific forecasts of
commodity prices and costs.
Unrecoverable Discovered Petroleum Initially-In-Place or Unrecoverable DPIIP is that portion of DPIIP 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.
Best Estimate of a resource represents 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
quantities actually recovered will equal or exceed the best estimate.
November 2014
39
Advisory Regarding Reserves and
Resource Disclosure
GLJ Petroleum Consultants Ltd. (“GLJ”) has updated its evaluation of the Discovered Petroleum Initially-In-Place (“DPIIP”) and the Economic
Contingent Resources (“ECR”) associated with the in-place petroleum. The evaluation was performed in accordance with National Instrument
51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) and the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”) and
is effective October 31, 2013.
Notes:
(1) All estimates of resources and reserves in the above table represent NuVista's gross resources, reserves or production before the deduction
of any royalties and without including any royalty interests of NuVista. There is no certainty that it will be commercially viable to produce any
portion of the resources. The resource estimates presented above use the resource categories set out in the COGE Handbook. See
“Reserves and Resource Disclosure”.
(2) The Cumulative Production numbers represent production to October 31, 2013 whereas the Proved plus Probable Reserves numbers are as of
December 31, 2012. From December 31, 2012 to October 31, 2013, total Cumulative Production from NuVista's Montney properties in the
reserve report was approximately 0.003 Tcfe. For further information regarding the previously reported reserves numbers, see NuVista's
Annual Information Form dated March 28, 2013.
(3) The Proved plus Probable Reserves estimate is effective as of December 31, 2012 and is based on an independent evaluation by GLJ using
January 1, 2013 forecast pricing. The Proved Reserves as of December 31, 2012 were estimated to be 0.094 Tcfe.
(4) All of NuVista's Contingent Resources from its Montney properties are considered economic using GLJ’s October 1, 2013 forecast prices.
(5) The primary contingency which prevents the classification of the ECR as reserves is pace and availability of funding. In addition, more drilling,
completion, and testing data will be required before NuVista can commit to the development of the ECR. Proved and Probable Reserves are
assigned to areas in proximity to proven producing Montney wells. ECR’s are assigned to areas that extend beyond the limits of Reserves. As
continued delineation drilling occurs, some resources currently classified as ECR are expected to be re-classified as Reserves.
(6) All of the DPIIP that has not been classified as Cumulative Production, Reserves or Contingent Resources may be considered 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. The Unrecoverable DPIIP has been calculated by subtracting Cumulative Production, Proved plus Probable Reserves and
Contingent Resources from DPIIP. Since the Proved plus Probable Reserves are estimated as of December 31, 2012 and all other numbers
are as of October 31, 2013 the Unrecoverable DPIIP may be greater or less that the number in the above table due to increases or decreases
in Proved plus Probable Reserves between December 31, 2012 and October 31, 2013.
(7) The sum of Cumulative Production, Reserves, Contingent Resources and Unrecoverable DPIIP do not add to DPIIP as Cumulative Production,
Reserves and Contingent Resources have been reduced to marketable sales volumes that have been shrunk to account for surface
loss. DPIIP and Unrecoverable DPIIP volumes are in-place volumes that have not been reduced due to surface loss.
November 2014
40
`