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CORPORATE PRESENTATION
MAY 2016
All amounts in Canadian dollars unless indicated otherwise
1
Advisory Regarding Forward-Looking
Information and Statements
May 2016
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; plans to maintain NuVista's balance sheet strength; profitably grow production
and funds from operations and develop NuVista's resource base, plans to focus on and improve processing and infrastructure; the benefits of NuVista's risk management program; the
anticipated benefits of NuVista's asset base; expected supply cost reductions; NuVista's 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; and other estimated operating, transportation, G&A and other costs; estimated liquid yields; netbacks, payouts, finding and
development costs, capital efficiencies, recycle ratio and estimated rates of return; NuVista's ability to fulfill all TOP obligations; guidance with respect to NuVista's capital expenditure
program, production mix, netback, funds from operations, targeted net debt levels and net debt to funds from operations ratios; 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.
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).
This presentation also contains future-oriented financial information and financial outlook information (collectively, "FOFI") about our prospective results of operations and funds from
operations, all of which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth in above. Readers are cautioned that the assumptions used in the
preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on FOFI and
forward-looking statements. NuVista’s actual results, performance or achievement could differ materially from those expressed in, or implied by, these FOFI and forward-looking statements,
or if any of them do so, what benefits NuVista will derive therefrom. NuVista has included the FOFI and forward-looking statements in this presentation in order to provide readers with a
more complete perspective on NuVista’s future operations and such information may not be appropriate for other purposes. The FOFI and 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.
2
NuVista Snapshot
Production (MBoe/d)
27% 50%
75% ~80%
28%
25%
17%
10 - 15%
0
5
10
15
20
25
30
2013* 2014 2015 2016E
Wapiti Montney Wapiti Sweet Other
TSX trading symbol: NVA
Market capitalization: ~$0.9 billion
Basic shares outstanding: 153.3 million
Bank debt capacity: $300 million
Percent Drawn (End Q1/16): 77%
Net Debt:Cashflow1: 2.1x
2016 Guidance
Production: 24,500 – 25,500 Boe/d
Capital investment: $115 – $135 million
Funds from operations2: $100 – $110 million
1 March 31, 2016 closing debt to Q116 Annualized Funds from Operations 2 Pricing Assumptions: $1.80/GJ AECO and US$45/Bbl WTI * Pro-forma 2013 Divestitures
Operating areas
WAPITI
EDMONTON
CALGARY
GRANDE PRAIRIE
May 2016
NuVista Corporate Info
3
NVA Principles and 2016 Guidance Focused on the Long Term… Flexibly managing the short term
May 2016
• Well costs down an additional 30% since 2014
• Continued improvement versus type curve
• Infrastructure spend complete for growth through 2018+
• Capex focused on well development in 2016, not on facilities
• G&A reduced by 1/2 over last 3 years, to $1.75/Boe for 2016
Reducing Costs & Improving Performance
• Net debt/funds flow from operations target under 2x
• Flexibility to dial spending quickly down or upwards as commodity prices change
• Disciplined approach to capital spending – large spend reduction for 2016, down nearly to 2016 funds from operations
Maintain Balance Sheet Strength
• Short term pace of spend minimized while preserving long term take-away plans
• Result is 10% to 15% production growth with minimal increase in debt
• Optimized 2016 development well economics 25% to 35% ROR and 2.0 to 3.0 year payout
Profitable Growth Tuned to Market Environment
Efficiency and Flexibility
4
The Alberta Condensate-Rich Montney … A sweet spot in a "world class" play
High
Quality
Reservoir
Overpressured 150-200 m thick
Condensate
Rich
1. Scalable/Repeatable
• Deposition on the shelf edge – not
isolated pockets
• Gas charged top to bottom
• Over-pressured – low water saturation
2. Porous and Permeable
• Hydrocarbon filled porosity up to 9%
(typically 4-5%)
• Sand/silt reservoir exhibits much better
permeability
3. Condensate-rich
• High liquids and condensate
demonstrated in all our wells to date
4. Thick Formation
• 150 – 200 metres
• Multiple developable layers of resource
May 2016
The Alberta Condensate-Rich Montney Industry Drilling and Production growth continues…
*Excludes southern areas of Alberta Condensate-rich Montney (Resthaven and Simonette). Map is an estimate of Industry land positions compiled from public data
• High level of industry activity continues
• > 850 Montney HZ wells licensed and/or drilled
to date
• Montney gas production exceeding 0.8 Bcf/d
Elmworth to Kakwa Montney HZ Activity Update*
May 2016
R9 W6 R10 W6
NuVista Encana Paramount Sinopec-Daylight CNRL Seven Generations Shell Apache Montney Licenses and Hz Wells
5
R6W6 R4W6 R2W6 R8W6
T65
T62
T61
T67
T69
T70
T68
T66
T64
T63
Elmworth to Kakwa Production Growth*
0
50
100
150
200
250
300
350
400
450
500
0
100
200
300
400
500
600
700
800
900
1000
Pro
du
cin
g H
z W
ell
Co
un
t
Avg
. Cal
en
dar
Day
Gas
(M
Mcf
/d)
Avg. Gas Rate Producing Well Count
6
0
1,000
2,000
3,000
4,000
5,000
6,000
0 5 10 15 20 25 30 35 40
De
pth
(m
)
Days
2013 2014 2015
Recent wells: 4,700m in 17 days; 5,500m in 21 days
Recent Wells
$0
$2
$4
$6
$8
$10
$12
2013 2014 2015E 2016E
($M
) Relentless Improvement Efficiency and Well Costs
May 2016
$0
$100
$200
$300
$400
$500
$600
2013 2014 2015E 2016E
($00
0)
• Drilling and completion costs coming down steadily from efficiency improvements
• Record drilling cost of $2.8 MM with 4,750 metres of total measured depth
• Record completion costs of <$2.0 MM; average completion cost per stage placed has now dropped below $130,000
• In-field gathering largely in place – majority of 2016 wells will be on-lease tie-ins; limited expiry/step-out drilling
Average Annual Montney Drilling Curves Montney Well Cost (DCET) By Year
Montney Drilling & Completion Cost per Stage Operational Highlights
Recent Record Wells:
4,750m in 17 days; 5,500m in 21 days
Last 5 wells outperforming
these 2016 budget
expectations
7
Relentless Improvement Bilbo Well Performance
May 2016
Bilbo Type Curve Progression
0
100
200
300
400
0 6 12 18 24
Cu
mu
lati
ve P
rod
uct
ion
(M
Bo
e)
Time (Months)
2013 Type Curve (4.4 Bcf; 35 Bbls/MMcf)
2014 Type Curve (4.4 Bcf; 45 Bbls/MMcf)
2015 Type Curve (4.4 Bcf; 75 Bbls/MMcf)
2016 Optimized Locations (5.0 Bcf; 66 Bbls/MMcf)
0
300
600
900
1,200
1,500
1,800
0 6 12 18 24
Sal
es
Pro
d (
Bo
e/d
)
Time (Months)
2016 Optimized Bilbo Well Production Profile
Two-year CTD production up 13% vs. 2015 and 38% vs. 2013
2016 Optimized Bilbo Total Production (Boe/d) 2016 Optimized Bilbo C5+ Production (Bbls/d)
NuVista's type curve based on Management's best estimates; Type Curve: Bcf = EUR; Bbls/MMcf = C5+ yield
Bilbo Well Production-to-Date
*Production groupings based off spud dates
0
100
200
300
400
500
600
0 6 12 18 24 30 36
Cu
mu
lati
ve P
rod
uct
ion
(M
bo
e)
Time (Months)
2015 Type Curve (4.4 Bcf, 75 bbl/MMcf)
2011-2013 (11 Wells)
2014 (12 Wells)
2015 (4 Wells)
8
Relentless Improvement Elmworth Well Performance
May 2016
Elmworth Type Curve Progression
0
100
200
300
400
0 6 12 18 24
Cu
mu
lati
ve P
rod
uct
ion
(M
Bo
e)
Time (Months)
2013 Type Curve (4.4 Bcf; 35 Bbls/MMcf)2014 Type Curve (4.4 Bcf; 45 Bbls/MMcf)2015 Type Curve (6.0 Bcf; 45 Bbls/MMcf)2016 Optimized Loc's (6.5 Bcf; 42 Bbls/MMcf)
0
300
600
900
1,200
1,500
1,800
0 6 12 18 24
Sal
es
Pro
d (
Bo
e/d
)
Time (Months)
2016 Optimized Elmworth Total Production (Boe/d) 2016 Optimized Elmworth C5+ Production (Bbls/d)
2016 Optimized Elmworth Well Production Profile
Two-year CTD production up 7% vs.
2015 and 45% vs. 2013
Elmworth Well Production-to-Date
0
100
200
300
400
500
600
700
0 6 12 18 24 30 36
Cu
mu
lati
ve P
rod
uct
ion
(M
bo
e)
Time (months)
2015 Type Curve (6 Bcf, 45 bbl/MMcf)
Small Frac (3 Wells)
Big Frac (9 Wells)
NuVista's type curve based on Management's best estimates; Type Curve: Bcf = EUR; Bbls/MMcf = C5+ yield *Production groupings based off spud dates
9
2016 Guidance Agility in Capex Reduction
May 2016
2015 Capital Expenditures ($MM)
$185
$67
$10 $11
DCET & Optimization
Facilities & Water Mgmt
Maintenance
Land, Seismic & Other
2016 Capital Expenditures ($MM)
$100
$10
$8 $6
2015 Highlights: • 18 Montney Wells drilled • Built Elmworth Compressor Station
2016 Highlights: • Flexible capex program; reduced from original
Budget of $140M-$160M • 10-11 Montney Wells in Bilbo & Elmworth • Minimal infrastructure spend
Development Focused
$273 MM $115-$135 MM
10
Montney Operations Activity Update
Bilbo
31 Producers (IP30) 2 New IP30's – 4 Additional on-stream
1 Well Completing
Elmworth 15 Wells Producing in the Development Block (IP30)
4 Elmworth Extension wells Producing (IP30) 2 New IP 30's – 2 Additional on-stream
1 Rig Drilling
Gold Creek 5 Producers (IP30)
No new IP 30's – 1 additional well on-stream
NVA New IP30
NVA Producing Montney (IP30)
NVA In-Progress Wells
Montney HZ’s
2016 Focus on Capital Efficiency
• Spud 10-12 wells in 2016 – all development wells
• Minimal Infrastructure Capex required – filling
existing facilities
• 2016 well performance expectations up 10-15%
over 2015
Attractive Land Tenure
• NuVista has over 135,000 gross acres of land
(210 sections @ 86% WI)
• Minimal 3rd party encumbrances
• Manageable expiries
Activity Highlights
• 4 New IP30's in Q1 – 7 additional wells on-stream
late April/Early May
• Reduced to 1 drilling rig for now
• Over 60 wells on production
May 2016
T70
T68
T66
R8W6 R6W6
T67
T69
R7W6
11
Elmworth Development Block Volume Ramp in-progress
May 2016
R9W6
T67
T68
NVA Montney IP30's
NVA In-Progress Wells
Montney Horizontal Wells
NVA Compressor Site
Connected to SemCAMS
R8W6
2 New IP30's
2 additional Wells just on-
stream
1 well drilling T69
0
1
2
3
4
5
6
7
8
9
Pro
du
ctio
n (
Mb
oe
d)
Sales Gas NGL's C5+
39 9
11
Cumulative-to-Date Bbls/MMcf
Condensate
Butane
Propane
North Montney Sales Production
Elmworth Well Performance
Raw Gas (Mcf/d)
C5+ (Bbl/d)
Total Sales
(Boe/d)
C5+ Yield (Bbl/
MMcf)
Well Count
IP30 6,442 318 1,330 49 15
IP60 5,884 267 1,189 45 13
IP90 5,375 237 1,078 44 13
IP180 4,170 172 838 41 9
IP360 3,193 126 636 39 8
12
Bilbo Development Block Focus on Efficient Production Additions in 2016
May 2016
NVA Montney IP30 Wells
NVA Montney In-Progress Wells
Montney Horizontal Wells
NVA 3-36 Compressor and connect
to Keyera R6W6
T65
T66
2 New IP30's
4 Wells recently on-stream
1 well to be completed
0
2
4
6
8
10
12
14
16
Pro
du
ctio
n (
Mb
oe
d)
Sales Gas NGL's C5+
76
5 5
Cumulative-to-Date Bbls/MMcf
Condensate
Butane
Propane
South Montney Sales Production
Bilbo Well Performance
Raw Gas (Mcf/d)
C5+ (Bbl/d)
Total Sales
(Boe/d)
C5+ Yield (Bbl/
MMcf)
Well Count
IP30 6,329 628 1,607 99 31
IP60 5,609 514 1,382 92 31
IP90 5,173 463 1,265 90 28
IP180 4,313 328 1,007 76 24
IP360 3,385 233 769 69 20
13
A Closer Look at the NuVista 'Boe' Condensate Underpins Economics and Provides
Torque to Oil Price Recovery
May 2016
NuVista Production Mix1
0
5,000
10,000
15,000
20,000
25,000
30,000
2013 2014 2015 2016E
71%
12%
17%
70%
22%
8% Nat Gas
Condensate
NGL's & Oil
NuVista 2016 Revenue Composition2
49%
49%
2%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
2016E
1 Pro-forma Divestitures 2 Based on WTI (USD/Bbl): $40.00; AECO (C$/GJ): $2.50; Fx (CAD:USD): 1.4:1
Bo
e/d
Hedged or Unhedged: Condensate is ~50% of revenue from 22% of total
production
14
WTI US$50.00/Bbl; AECO C$2.75/GJ
Realized Price2 $32.25/Boe
Profit $8.25/Boe
Margin 26%
Recycle Ratio 1.2x
NuVista Montney Recycle Ratio and
Profitability… Tremendous Torque to Oil
and Gas Price
May 2016
Full-Cycle Bilbo F&D Cost
Well Cost (DCET) $7.3 MM
Land/Seismic/Facilities $0.6 MM
Full-Cycle Cost $7.9 MM
2016 Bilbo Type Curve EUR1 1.12 MBoe
Full-Cycle F&D Cost $7.00/Boe
2016E Montney Cash Costs
Operating Cost $11.00/Boe
Transportation $1.75/Boe
Royalties $1.50/Boe
G&A $1.75/Boe
Interest $1.00/Boe
Total Cash Cost $17.00/Boe
1NuVista's type curve based on Management's best estimates 2Unhedged Bilbo realized price
Torque to Oil and Gas Prices
WTI US$60.00/Bbl; AECO C$3.25/GJ
Realized Price2 $38.00/Boe
Profit $13.75/Boe
Margin 36%
Recycle Ratio 2.0x
WTI US$40.00/Bbl; AECO C$2.25/GJ
Realized Price2 $27.00/Boe
Profit $3.50/Boe
Margin 13%
15
Wapiti Montney … Firm Egress Counts Built-in growth with generous capital flexibility in the short term …
… and multiple options for the long term
CNRL Gold Creek Plant
Keyera Simonette Plant
SemCAMS K3 Plant SemCAMS Raw Gas Pipeline
Keyera Raw Gas and c5+
Pipeline
Alliance Sales Line
TCPL Sales Line
NuVista (100%) Bilbo
Compressor Station
Raw Gas Capacity – 80 MMcf/d
Condensate Cap'y – 8,000 Bbl/d
NuVista (100%) Elmworth
Compressor Station
Raw Gas Capacity – 80 MMcf/d
Condensate Cap'y – 4,000 Bbl/d
NuVista (50%) North
Compressor Station
Raw Gas Capacity – 20 MMcf/d
Grande Prairie
Proposed 2018 Wapiti Area Gas Plants
May 2016
16
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
45,000
0
20
40
60
80
100
120
140
160
180
200
Mo
ntn
ey C
ap
acit
y –
Bo
e/d
Mo
ntn
ey R
aw
Ga
s C
ap
acit
y -
MM
cf/
d
SemCAMS Keyera Min TOP Commitment
30 MMcf/d
2016 Montney Production 20,000+ Boe/d
15,000+ Boe/d of Future Growth Capacity in Place
2013 2016 2015 2014
Wapiti Montney Processing Capacity Firm Capacity with TOP flexibility built in
All products have virtually 100% FIRM downstream take-away
2017
15 MMcf/d
30 MMcf/d
35 MMcf/d
17 MMcf/d
30 MMcf/d
May 2016
New Sour Gas
Plant
17
2015 Year-end Reserves Report
2015 Year-end Reserves Report – GLJ Petroleum Consultants Ltd.
• PDP reserves volume increased 40% before production and dispositions, or 13% after
• Corporate TP+PA reserves volume increased by 15%
• Corporate TP+PA F&D of $3.69/Boe & TP F&D of $8.11/Boe – 2015 Corporate Netback
$15.28/Boe – TP+PA Recycle Ratio 4.1x & TP Recycle Ratio 1.9x
• Corporate TP+PA B-Tax NPV10% decreased 25% to $1.1 billion primarily due to a ~30%
reduction in GLJ's price forecast*
• Reserve Life Index now at ~27 years and ~13 years on a TP+PA and TP basis, respectively
• Montney TP+PA average reserves per well increased 4% vs. 2014; Montney TP+PA well
locations now 253, an increase of 23% compared to year end 2014
12 29
86
184 225
98 65
53
36
28
0
50
100
150
200
250
300
2011 2012 2013 2014 2015
Other Wapiti Montney
Corporate TP+PA Reserves (MMBoe)
253
87 167
847
1,155 938
1,197
612
476
251
120
0
200
400
600
800
1,000
1,200
1,400
1,600
2011 2012 2013 2014 2015
Other Wapiti Montney
Corporate TP+PA NPV10% ($MM)
1,058
Corporate TP+PA Reserves by Area
* Based on first 3 yr avg prices See Appendix for important disclosures regarding Reserves May 2016
89%
9%
2%
MTY
W6 SWT
Non-W6
18
Commodity Price Risk Management We are well hedged with under 10% AECO exposure for 2016
May 2016
Floor C$ WTI price of
$77.17/Bbl on ~53% of
2016 Q2-Q4 net
production
Floor AECO price of
$3.30/Mcf on ~73% of
2016 Q2-Q4 net
production
Basis includes some Chicago pricing. Includes NYMEX hedges converted to an AECO equivalent price.
20.00
40.00
60.00
80.00
100.00
500
1,000
1,500
2,000
2,500
3,000
3,500
2016 Q2 2016 Q3 2016 Q4 2017 Q1 2017 Q2
Pri
ce, C
$/B
bl
He
dge
d V
olu
me
, Bb
l/d
Crude Oil Hedge Position
Bbl/d Capped Bbl/d Uncapped Avg. Floor Avg. Ceiling
0.75
1.50
2.25
3.00
3.75
4.50
20,000
40,000
60,000
80,000
100,000
120,000
2016Q2
2016Q3
2016Q4
2017Q1
2017Q2
2017Q3
2017Q4
2018Q1
2018Q2
2018Q3
2018Q4
2019Q1
Pri
ce, C
$/G
J
He
dge
d V
olu
me
, GJ/
d
Natural Gas Hedge Position
GJ/d Capped GJ/d Uncapped GJ/d AECO-NYMEX Basis Avg. Floor Avg. Ceiling
Only 5% of gas volumes
exposed to AECO this
summer
19
Funds from Operations and netbacks hanging in there despite low commodity prices
45% 31%
52%
66% 72% 72% 79%
81%
17,823 14,493
18,030
23,165 23,215 21,448 21,622
23,355 25,484
-
5,000
10,000
15,000
20,000
25,000
30,000
Q114 Q214 Q314 Q414 Q115 Q215 Q315 Q415 Q116
Wapiti Montney Other Properties
NuVista Operating Results 2016 Guidance
Corporate Production (Boe/d)
Funds from Operations
2016 Actual Production (Boe/d)
Guidance (Boe/d)
Q1 25,484 24,500 - 25,000
2016 FY - 24,500 - 25,500
$19.26
$11.42
$16.47 $17.22
$14.52 $15.53 $16.00 $15.15
$13.06
$0
$5
$10
$15
$20
$25
$0
$5
$10
$15
$20
$25
$30
$35
$40
$45
$50
Q114 Q214 Q314 Q414 Q115 Q215 Q315 Q415 Q116
($/B
OE)
($M
M)
Funds from Operations ($MM) Funds from Operations ($/BOE)
May 2016
2016 Actual Capex ($MM)
2016 Capex Guidance Range
($MM)
Q1 $61 -
2016 FY $115 - $135
76%
2016 Actual Funds from Operations
($MM)
2016 Funds from Operations
Guidance Range ($MM) (1)
Q1 $30 -
2016 FY $100 - $110
(1) Based on commodity pricing of US$45/Bbl WTI and $1.80/GJ AECO
20
Balance sheet comes first
Top plays win at any price, wells keep improving
Focused capital discipline & reducing unit costs
No material unutilized TOP cost concerns
2016 Growth despite muted spending
Hedging – strong downside protection through 2016+
NuVista: Looking Forward Flexibility and Strength in a Volatile Environment
We have the Assets We have the Will We have the Team
We have the Strategy… To Deliver
May 2016
21
Advisory Regarding Oil and Gas
Information & Other Advisories
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 Tcfe (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.
Any references in this presentation to initial production rates are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such
wells will continue production and decline thereafter. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for NuVista.
NuVista has presented certain typecurves and well economics which are based on NuVista’s historical production in the Bilbo and Elmworth development areas, in addition to production
history from analogous Montney developments located in close proximity to the Wapiti area. Such type curves and well economics are useful in understanding management's assumptions of
well performance in making investment decisions in relation to development drilling in the Montney area and for determining the success of the performance of development wells; however,
such type curves and well economics are not necessarily determinative of the production rates and performance of existing and future wells. In this presentation, estimated ultimate recovery
represents the estimated ultimate recovery associated with the type curves presented; however, there is no certainty that NuVista will ultimately recover such volumes from the wells it drills.
In presenting such type curves, inputs and economics information, NuVista has used a number of oil and gas metrics which do not have standardized meanings and therefore may be
calculated differently from the metrics presented by other oil and gas companies. Such metrics include "Development Well Capital", "raw EUR", "NPV10", "PIR", "payout", "ROR", "netback",
"F&D" and "capital efficiency". Development well capital includes all capital spent to drill, complete, equip and tie-in a well. Raw EUR represents the estimated ultimate recovery of resources
associated with the type curves presented. NPV 10 represents the anticipated net present value of the future net revenue discounted at a rate of 10% associated with the type curves
presented. PIR (Profit to Investment Ratio) is the ratio of the NPV 10 relative to the development well capital. Payout means the anticipated years of production from a well required to fully
pay for the development well capital of such well. ROR means the rate of return of a well or the discount rate required to arrive at a NPV equal to zero. Netback equals total revenues on a
BOE basis (excluding realized commodity derivative gains/losses) less royalties, transportation and operating costs. F&D is the anticipated full exploration and development costs associated
with each barrel of oil equivalent expected to be recovered from a well based on the type curves and economics presented. Capital efficiency is a measure of expected development well
capital divided by average first year production results (IP365) from such well based on the type curve presented.
It should not be assumed that the future net revenues (NPV10) included in this presentation represent the fair market value of the reserves. The estimates of reserves and future net revenue
for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties due to the effects of aggregation.
NON-GAAP MEASUREMENTS
Within this presentation, references are made to terms commonly used in the oil and natural gas industry. Management uses funds flow, debt to annualized funds from operations and
netback to analyze operating performance and leverage. Funds from operations as presented, does not have any standardized meaning prescribed by GAAP and therefore it may not be
comparable with the calculation of similar measures for other entities. All references to funds from operations throughout this presentation are based on cash flow from operating activities
before changes in non-cash working capital, environmental remediation expenses, note receivable allowance (recovery) and asset retirement expenditures. Netbacks equals total revenues
excluding realized commodity derivative gains/losses less royalties, transportation and operating costs. Debt (net debt) is calculated as long-term debt plus current assets less current
liabilities and excludes the current portions of the commodity derivative asset or liability.
May 2016
22
Advisory Regarding Reserves
Disclosure
RESERVES DISCLOSURE The reserves estimates prepared herein have been evaluated by an independent qualified reserves evaluator in accordance with NI 51-101 and the COGE Handbook and is effective
December 31, 2015 and is based on an independent evaluation by GLJ using January 1, 2016 forecast pricing. The reserves have been categorized accordance with the reserves and
resource definitions as set out in the COGE Handbook, which are set out below:
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.
May 2016
23
APPENDIX
May 2016
24
Significant New Wells On-stream New Record Wells at Bilbo and Significant Step-out at Elmworth
May 2016
Bilbo 01-34 Well Bilbo 16-27 Well
Elmworth 01-01 Step-out Well
0
3,000
6,000
9,000
12,000
15,000
18,000
0
1,000
2,000
3,000
4,000
5,000
6,000
0 10 20 30 40 50
Gas
Rat
e (
mcf
/d)
C5
+ R
ate
(b
bl/
d)
Production Days
C5+ Actual (bbl/d) C5+ Type Curve (bbl/d)
Gas Actual (mcf/d) Gas Type Curve (mcf/d)
0
3,000
6,000
9,000
12,000
15,000
0
1,000
2,000
3,000
4,000
5,000
0 10 20 30 40 50
Gas
Rat
e (
mcf
/d)
C5
+ R
ate
(b
bl/
d)
Production Days
C5+ Actual (bbl/d) C5+ Type Curve (bbl/d)
Gas Actual (mcf/d) Gas Type Curve (mcf/d)
0
2,000
4,000
6,000
8,000
10,000
12,000
0
400
800
1,200
1,600
2,000
2,400
0 5 10 15 20
Gas
Rat
e (
mcf
/d)
C5
+ R
ate
(b
bl/
d)
Production Days
C5+ Actual (bbl/d) C5+ Type Curve (bbl/d)Gas Actual (mcf/d) Gas Type Curve (mcf/d)
25
Condensate Pricing Strong demand and premium price for the long term
• Condensate is used in Alberta as a diluent
to ship heavy oil on pipelines
• Condensate in Alberta is typically priced at a
premium to crude oil
• US condensate supply is increasing
• But condensate export restrictions are
easing
• 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 still does
Western Canada Condensate Supply and Demand
May 2016
Western Canadian Condensate Pricing
26
WAPITI
MONTNEY
FAIRWAY
Focus on Wapiti Our lands contain the Montney with the bonus
of significant Deep Basin uphole potential
Wapiti Uphole Zones
DUNVEGAN
NOTIKEWIN
FALHER
BLUESKY
GETHING
CADOMIN
NIKANASSIN A
NIKANASSIN C
LOWER MONTNEY
MIDDLE MONTNEY
CADOTTE
Wapiti Montney area uphole potential:
The Montney is overlain by a 1.5 km
thickness of high potential wet gas and oil
Jurassic/Cretaceous deep basin formations … over an area of 100,000+ Ac
Acr
es 0
00's
Du
nve
gan
Fal
her
Wilr
ich
Cad
om
in
Nik
anas
sin
Gross 90 112 104 111 119
Net 48 49 48`` 57 97
-
1,000
2,000
3,000
4,000
5,000
6,000
Pro
du
ctio
n (
Bo
e/d
)
Liquids
Natural Gas
Downstream Nova
Restrictions
May 2016
27
Montney Delineation Large Portfolio of Development Opportunities
May 2016
Elmworth
Development Block
Expanded
Bilbo
Development
Block
Gold Creek Development Area is Emerging
• 5 producers and 1 test indicative of an emerging development block
• Area tied-in to NuVista Infrastructure
• Gas IP30's up to 7 MMcf/d (choked) and Condensate rates over 475 Bbls/d
• IP30 CGR's range from 55 to 161 Bbls/MMcf
• Sub-block type-curve(s) to be established with additional well results
Bilbo Development Block Expanded
• Powerful South step-out well – far above typecurve
• Expands Bilbo Development block to include all NuVista lands
NVA Producing Montney
Montney HZ’s New Block SW of Elmworth is Emerging
• Three successful step-out results
• Encouraging initial gas rates and evidence of material condensate content
extending to the southwest
• H2S in-line with Elmworth Block
• Specifics of type-curve to be established
R8W6 R6W6
T65
T67
T69
28
Lower Montney Activity NuVista Data Collection In Progress
Elmworth
Wapiti
South Wapiti
Gold Creek
Bilbo
Kakwa
Karr
Pipestone
SCL 1-33-67-5W6 Producing
7Gen 13-24-65-5W6 Producing (dual lateral)
7Gen 12-32-64-5W6 Producing
7Gen 15-22-63-3W6 Producing
Confidential 30-Jan-2016
NVA Lands Montney Wells LWR Montney A Wells LWR Montney Cores
• Multiple pilot wells in progress by
industry – Early Production Data
Emerging
• NuVista has good distribution of
vertical wells and cores
• NuVista vertical completion: over
pressured, condensate-rich
• NuVista pilot deferred until
commodity price recovery
NVA 15-13-68-7W6 Vertical Over-pressured – 133 Bbls/MMcf condy
May 2016
ACL 1-7-67-7W6 Producing
Confidential: 07-Oct-2015
SCL 9-27-66-7W6 Confidential: 14-Feb-2016
T70
T68
T66
R9W6 R7W6 R5W6 R3W6
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