CORPORATE PRESENTATION JUNE 2016

CORPORATE PRESENTATION
JUNE 2016
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; 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.
June 2016
1
NuVista Snapshot
NuVista Corporate Info (June 30, 2016E)
TSX trading symbol:
Market capitalization:
Basic shares outstanding:
Bank revolver capacity:
Percent Drawn:
Net Debt:Cashflow1:
GRANDE PRAIRIE
NVA
~$1.0 billion
156.6 million
$200 million
45%
1.5x
2016 Guidance
Production:
Capital investment:
WAPITI
23,500 – 24,500 Boe/d
$165 – $175 million
Funds from operations2:
$110 – $120 million
Production (MBoe/d)
EDMONTON
30
25
20
17%
15
CALGARY
10
5
0
Operating areas
28%
27%
2013*
1
June 2016
25%
June 2016 est. debt to Q116 Annualized Funds from Operations
2 Pricing
75%
~90%
95+%
50%
2014
Wapiti Montney
Assumptions: $2.10/GJ AECO and US$50/Bbl WTI
2015
2016E
2017E
Wapiti Sweet
Other
* Pro-forma 2013 Divestitures
2
NVA Principles and 2016 Guidance
Focused on the Long Term… Flexibly managing the short term
Maintain Balance Sheet
Strength
Profitable Growth Tuned
to Market Environment
• Net debt/funds flow from
operations target under 2x and
falling as strip pricing rises
•
• Flexibility to dial spending
quickly down or upwards as
commodity prices change
•
• Disciplined approach to capital
spending
Short term pace of spend
minimized while preserving
long term take-away plans
Reducing Costs &
Improving Performance
•
Well costs down an additional
30% since 2014
•
Result is 10% to 20%
production per share growth
with ~flat debt
Continued improvement versus
type curve
•
•
2017 cash flow per share
growth 15 to 50%(1)
Infrastructure spend complete
for growth through 2018+
•
•
Optimized 2016 development
well economics 30% to 60% IRR
and 1.5 to 3.0 year payout(1)
Capex focused on well
development in 2016-17, not
on facilities
•
G&A reduced by 1/2 over last
3 years, to $1.75/Boe for 2016
Efficiency and Flexibility
June 2016
(1)Range
refers to Strip and Upside pricing cases, refer to Slide 7 for detailed assumptions
3
The Alberta Condensate-Rich Montney
… A sweet spot in a "world class" play
1. Scalable/Repeatable
• Deposition on the shelf edge – not
isolated pockets
• Gas charged top to bottom
• Over-pressured – low water saturation
High
Quality
Reservoir
2. Porous and Permeable
• Hydrocarbon filled porosity up to 9%
(typically 4-5%)
• Sand/silt reservoir exhibits much better
permeability
Overpressured
150-200 m thick
3. Condensate-rich
• High liquids and condensate
demonstrated in all our wells to date
4. Thick Formation
Condensate
Rich
• 150 – 200 metres
• Multiple developable layers of resource
June 2016
4
The Alberta Condensate-Rich Montney
Industry Drilling and Production growth continues…
Elmworth to Kakwa Montney HZ Activity Update*
• High level of industry activity continues
T70
• > 850 Montney HZ wells licensed and/or drilled
to date
T69
T68
• Montney gas production exceeding 0.8 Bcf/d
T67
Elmworth to Kakwa Production Growth*
900
Avg. Gas Rate
Producing Well Count
500
800
400
700
350
600
300
500
250
400
200
300
150
200
100
100
50
0
June 2016
T65
450
0
Producing Hz Well Count
Avg. Calendar Day Gas (MMcf/d)
1000
T66
T64
NuVista
Encana
Paramount
Sinopec-Daylight
CNRL
Seven Generations
Shell
Apache
Montney Licenses
and Hz Wells
R10R9
W6W6
T63
T62
T61
R8W6
R6W6
R4W6
*Excludes southern areas of Alberta Condensate-rich Montney (Resthaven and Simonette). Map is an estimate of Industry land positions compiled from public data
R2W6
5
2016 Capital Guidance
Ability to Adapt to Commodity Price Environment
2015A FY Capex
($MM)
2016FY Capex – March Forecast
($MM)
DCET & Well Optimization
Facilities & Water Mgmt
Maintenance
Other
$6
$8 $6
$8
$11
$10
$14
$10
$67
$185
Development
Focused
$100
Incremental Wells
with Robust
Economics
$273 MM
$115-$135 MM
2015 Highlights:
•
18 Montney Wells drilled
•
Built Elmworth Compressor Station
March 2016 Highlights:
•
Flexible capex program; reduced
from orig. Budget of $140M-$160M
•
10-11 Wells in Bilbo & Elmworth
•
Minimal infrastructure spend
June 2016
2016FY Capex – June Forecast
($MM)
$140
$165-$175 MM
June 2016 Highlights:
•
Increased capex as a result of
proceeds from strategic initiatives
•
Incremental development wells
added: total of ~18 Wells now
planned
6
Funded Growth Plan at Strip and
Upside Pricing…
Production (MBoe/d)
Capital Expenditures ($MM)
$300
$273
Upside Case
Strip Case
35
Upside Case
Strip Case
29.0
30
25
$200
$273
$175(2)
$10
$165
$100
2015A
2016E
$180
$40
$140
Upside Case
22.4
23.5
2015A
2016E
2017E
2016E
2017E
26.0
10
2017E
Debt ($MM)(1)(3)
Cashflow(1) ($MM)
$200
22.4
20
15
3.0
24.5
1.0
Strip Case
Term Debt
$175
Bank Debt
$250
$150
$100
$125
$125
$50
$120
$10
$110
$150
$125
$50
$50
2015A
(1)Assumptions:
June 2016
2016E
2017E
2016 STRIP & UPSIDE: US$46/bbl WTI; C$2.00/GJ AECO; 1.31:1.0 C$:USD
2017 STRIP: US$51/bbl WTI; C$2.60/GJ AECO; 1.31:1.0 C$:USD
2017 UPSIDE: US$60/bbl WTI; C$3.00/GJ AECO; 1.27:1.0 C$:USD
2015A
(2) 2016 Capex approximately $100MM net of
June 2016 W6 Asset Divestiture proceeds
(3) Working Capital Deficit not illustrated, which
estimated to be approximately $20MM
7
Relentless Improvement
Efficiency and Well Costs
Average Annual Montney Drilling Curves
Montney Well Cost (DCET) By Year
0
$12
2013
$8
2,000
Recent Wells
3,000
$6
4,000
$4
RecentRecord
wells:
Recent
4,700mWells:
in 17 days;
5,500m in 17
21 days;
days
4,750m
5,500m in 21 days
5,000
$2
6,000
$0
2013
2014
2015E
0
2016E
Montney Drilling & Completion Cost per Stage
$600
$400
$300
$200
$100
$0
2013
June 2016
2014
2015E
2016E
5
10
15
20
Days
25
30
35
40
Operational Highlights
Last 5 wells
outperforming
these 2016
budget
expectations
$500
($000)
2015
Depth (m)
1,000
($M)
$10
2014
• 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
8
Relentless Improvement
Bilbo Well Performance
Bilbo Type Curve Progression
700
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)
300
2015 Type Curve (4.4 Bcf, 75 bbl/MMcf)
2011-2013 (11 Wells)
2014 (12 Wells)
2015+ (10 Wells)
600
200
Two-year CTD
production up 13% vs.
2015 and 38% vs. 2013
100
500
0
0
6
12
Time (Months)
18
24
2016 Optimized Bilbo Well Production Profile
1,800
2016 Optimized Bilbo Total Production (Boe/d)
2016 Optimized Bilbo C5+ Production (Bbls/d)
1,500
Cumulative Production (Mboe)
Cumulative Production (MBoe)
400
Bilbo Well Production-to-Date
400
300
Sales Prod (Boe/d)
200
1,200
900
100
600
300
0
June 2016
6
12
Time (Months)
18
24
NuVista's type curve based on Management's best estimates; Type Curve: Bcf = EUR; Bbls/MMcf = C5+ yield
36
30
24
18
12
6
0
0
0
Time (Months)
*Production groupings based off spud dates
9
Relentless Improvement
Elmworth Well Performance
Elmworth Type Curve Progression
700
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)
300
2015 Type Curve (6 Bcf, 45 bbl/MMcf)
Small Frac (3 Wells)
Big Frac (12 Wells)
600
200
Two-year CTD
production up 7% vs.
2015 and 45% vs. 2013
100
500
0
0
6
12
Time (Months)
18
24
2016 Optimized Elmworth Well Production Profile
1,800
2016 Optimized Elmworth Total Production (Boe/d)
2016 Optimized Elmworth C5+ Production (Bbls/d)
1,500
Cumulative Production (Mboe)
Cumulative Production (MBoe)
400
Elmworth Well Production-to-Date
400
300
200
900
100
600
300
0
June 2016
6
12
Time (Months)
18
24
NuVista's type curve based on Management's best estimates; Type Curve: Bcf = EUR; Bbls/MMcf = C5+ yield
36
30
24
18
0
12
6
0
0
Sales Prod (Boe/d)
1,200
Time (months)
10
Montney Operations
Activity Update
R8W6
Activity Highlights
• 4 New IP30's in Q1 – 4 Additional IP30's in Q2
R7W6
T70
R6W6
Elmworth
16 Wells Producing in the Development Block (IP30)
4 Elmworth Extension wells Producing (IP30)
1 New IP 30 – 1 Additional on-stream
1 Rig Drilling
• Increasing to 2 Rigs in Q3
• >60 wells on production
T69
2016 Focus on Capital Efficiency
•
Increasing Montney Activity post-W6 Divestiture
•
~18 Montney wells planned in 2016
•
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)
Gold Creek
6 Producers (IP30)
One new IP 30
T68
New Gold Creek IP30:
T67
Bilbo
33 Producers (IP30)
2 New IP30's – 2 Additional on-stream
T66 1 New Extended-reach well completed (onstream in July)
4.4 MMcf/d (flat)
710 Bbl/d
1,355 Boed
160 Bbl/MMcf
NVA New IP30
NVA Producing Montney (IP30)
•
Minimal 3rd party encumbrances
NVA In-Progress Wells
•
Manageable expiries
Montney HZ’s
June 2016
Raw Gas:
Condensate:
Total Sales:
CGR:
11
Elmworth Development Block
Volume Ramp in-progress
R9W6
T69
North Montney Sales Production
1 New IP30
R8W6
2 Additional Wells Recently On-Stream
1 Rig Drilling
9
Cumulative-to-Date
Production (Mboed)
7
6
Sales Gas
Bbls/MMcf
8
NGL's
C5+
11
Condensate
9
Butane
39
Propane
5
4
3
2
1
T68
0
Elmworth Well Performance
T67
NVA Montney IP30's
NVA In-Progress Wells
Montney Horizontal Wells
NVA Compressor Site
Connected to SemCAMS
June 2016
IP30
IP60
IP90
IP180
IP360
Raw Gas
(Mcf/d)
C5+
(Bbl/d)
Total
Sales
(Boe/d)
C5+ Yield
(Bbl/
MMcf)
Well
Count
6,305
312
1,298
49
16
5,662
268
1,154
47
15
5,375
236
1,078
44
13
4,169
172
837
41
9
3,186
126
635
39
8
12
Bilbo Development Block
Focus on Efficient Production Additions in 2016
South Montney Sales Production
2 New IP30's
2 Wells Recently On-Stream
1 Well Completed
16
T66
Cumulative-to-Date
Bbls/MMcf
Two New Step-Out IP30's Avg/Well:
Raw Gas:
Condensate:
Total Sales:
CGR:
6.3 MMcf/d
842 Bbl/d
1,732 Boed
134 Bbl/MMcf
T65
Production (Mboed)
12
10
Sales Gas
Condensate
14
5
5
NGL's
C5+
Butane
Propane
76
8
6
4
2
0
Bilbo Well Performance
NVA Montney IP30 Wells
NVA Montney In-Progress Wells
R6W6
June 2016
IP30
Raw Gas
(Mcf/d)
C5+
(Bbl/d)
Total
Sales
(Boe/d)
C5+
Yield
(Bbl/
MMcf)
Well
Count
6,341
642
1,618
101
33
Montney Horizontal Wells
IP60
5,604
515
1,383
92
31
NVA 3-36 Compressor and connect
to Keyera
IP90
5,123
450
1,245
88
31
IP180
4,331
343
1,021
79
26
IP360
3,235
226
737
70
22
13
A Closer Look at the NuVista 'Boe'
Condensate Underpins Economics and Provides
Torque to Oil Price Recovery
NuVista 2016 Revenue Composition(2)
NuVista Production Mix(1)
100%
25,000
90%
80%
20,000
Boe/d
8%
Nat Gas
22%
15,000
10,000
2%
70%
60%
Condensate 50%
70%
NGL's & Oil
17%
40%
30%
12%
5,000
49%
20%
71%
49%
10%
0
2013
2014
2015
2016E
0%
2016E
Hedged or Unhedged: Condensate is
~50% of revenue from 22% of total
production
June 2016
(1)
Pro-forma Divestitures
(2)
Based on WTI (USD/Bbl): $40.00; AECO (C$/GJ): $2.50; Fx (CAD:USD): 1.4:1
14
Wapiti Montney … Firm Egress Counts
Built-in growth with generous capital flexibility in the short term …
… and multiple options for the long term
Grande Prairie
Proposed 2018 Wapiti Area Gas Plants
NuVista (50%) North
Compressor Station
Raw Gas Capacity – 20 MMcf/d
CNRL Gold Creek Plant
NuVista (100%) Elmworth
Compressor Station
Raw Gas Capacity – 80 MMcf/d
Condensate Cap'y – 4,000 Bbl/d
NuVista (100%) Bilbo
Compressor Station
Raw Gas Capacity – 80 MMcf/d
Condensate Cap'y – 8,000 Bbl/d
Keyera Simonette Plant
SemCAMS Raw Gas Pipeline
SemCAMS K3 Plant
Keyera Raw Gas and c5+
Pipeline
Alliance Sales Line
TCPL Sales Line
June 2016
15
Wapiti Montney Processing Capacity
Firm Capacity with TOP flexibility built in
All products have virtually 100% FIRM downstream take-away
200
45,000
180
New Sour Gas
40,000 Plant
160
35,000
30 MMcf/d
140
30,000
120
30 MMcf/d
25,000
15 MMcf/d
20,000
30 MMcf/d
15,000
100
80
60
Montney Capacity – Boe/d
Montney Raw Gas Capacity - MMcf/d
2016 Montney Production 20,000+ Boe/d
15,000+ Boe/d of Future Growth Capacity in Place
10,000
40
35 MMcf/d
5,000
20
0
2013
2014
SemCAMS
June 2016
2015
Keyera
2016
17 MMcf/d
2017
0
Min TOP Commitment
16
Commodity Price Risk Management
We are well hedged with under 10% AECO exposure for 2016
Crude Oil Hedge Position
3,500
100.00
2,000
60.00
1,500
40.00
1,000
Floor C$ WTI price of
$77.17/Bbl on ~52% of
2016 Q2-Q4 net
production
20.00
500
2016 Q2
2016 Q3
Bbl/d Capped
2016 Q4
Bbl/d Uncapped
2017 Q1
2017 Q2
Avg. Floor
Avg. Ceiling
Natural Gas Hedge Position
120,000
Hedged Volume, GJ/d
Price, C$/Bbl
80.00
2,500
4.50
100,000
3.75
80,000
3.00
60,000
2.25
40,000
1.50
20,000
0.75
2016
Q2
2016
Q3
GJ/d Capped
June 2016
2016
Q4
2017
Q1
2017
Q2
GJ/d Uncapped
2017
Q3
2017
Q4
2018
Q1
2018
Q2
GJ/d AECO-NYMEX Basis
2018
Q3
2018
Q4
Avg. Floor
Basis includes some Chicago pricing. Includes NYMEX hedges converted to an AECO equivalent price.
Price, C$/GJ
Hedged Volume, Bbl/d
3,000
Floor AECO price of
$3.30/Mcf on ~71% of
2016 Q2-Q4 net
production
Only 5% of gas volumes
exposed to AECO this
summer
2019
Q1
Avg. Ceiling
Hedging position shown is post-W6 asset sale circa July 1, 2016
17
NuVista Operating Results
2016 Guidance
Corporate Production (Boe/d)
30,000
Wapiti Montney
25,000
20,000
15,000
Q114
21,448 21,622
25,484
Q1
25,484
24,500 - 25,000
2016 FY
-
23,500 - 24,500
14,493
66%
45%
23,215
23,355
18,030
10,000
5,000
Guidance
(Boe/d)
Other Properties
23,165
17,823
2016 Actual
Production (Boe/d)
72%
76%
72%
79%
81%
2016 Actual Funds
from Operations
($MM)
2016 Funds from
Operations
Guidance Range
($MM) (1)
$30
-
52%
31%
Q214
Q1
Q314
Q414
Q115
Q215
Q315
Q415
Q116
2016 FY
$110 - $120
Funds from Operations
$45
$40
Funds from Operations ($MM)
$19.26
$16.47 $17.22
$35
($MM)
$25
Funds from Operations ($/BOE)
$30
$14.52 $15.53
$16.00 $15.15
$13.06
$11.42
$25
2016 Actual Capex
($MM)
2016 Capex
Guidance Range
($MM)
$61
-
$20
Q1
$15
$10
$20
($/BOE)
$50
2016 FY
$165 - $175
$15
$5
$10
$5
$0
$0
Q114
June 2016
Q214
Q314
Q414
Q115
Q215
Q315
Q415
Funds from Operations and netbacks hanging in there
despite low commodity prices
Q116
(1) Based on commodity pricing of US$50/Bbl WTI and $2.10/GJ AECO
18
NuVista Looking Forward
Flexibility and Strength in a Volatile Environment






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
Increasing our growth in stages as strip prices move up
Hedging – strong downside protection through 2016+
but with full torque to oil prices 2017+
We have the Assets We have the Will
We have the Team
We have the Strategy… To Deliver
June 2016
19
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.
June 2016
20
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.
June 2016
21
APPENDIX
June 2016
22
Gold Creek Delineation
Continued Encouragement…
13-25 Shut-in pending tie-in
IP30
Well
Raw Gas
(MMcf/d)
C5+
(Bbls/d)
16-19
13-25
1-28
16-01
16-27
8-12
6.8
1.8
2.9
7.3
4.6
4.4
377
263
462
489
256
710
Total Sales C5+ Yield
(Boe/d)
(Bbl/MMcf)
1,307
543
876
1,635
1,044
1,355
56
146
161
67
55
160
8-12 New IP30
16-1 On-production
16-19 On-production
Cumulative Production to Date (June 15, 2016)
Well
Cumulative
Total
Days on C5+ Yield Condensate Sales Gas
Prod
(Bbl/MMcf) (Mbbls)
(MMcf)
(MBoe)
16-19
339
56
52
775
197
13-25
232
123
36
257
81
1-28
451
121
120
860
270
16-01
245
49
40
694
170
16-27
322
40
39
832
193
June 2016
16-27 On-production
1-28 On-production
23
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 $1.1 billion primarily due to a ~30%
reduction in GLJ's price forecast*
•
Reserve Life Index now at ~27 years and ~13 years on a TP+PA and TP basis, respectively
•
Montney TP+PA average reserves per well increased 4% vs. 2014; Montney TP+PA well
locations now 253, an increase of 23% compared to year end 2014
Corporate TP+PA Reserves (MMBoe)
253
250
28
36
200
2%
1,400
MTY
9%
251
1,200
W6 SWT
1,058
476
1,000
Non-W6
120
800
150
225
53
100
0
Corporate TP+PA Reserves by Area
1,600
300
50
Corporate TP+PA NPV10% ($MM)
184
98
65
12
2011
29
Other
June 2016
1,155
612
938
847
200
0
2013
1,197
400
86
2012
600
2014
2015
Wapiti Montney
* Based on first 3 yr avg prices
87
167
2011
2012
Other
89%
2013
2014
2015
Wapiti Montney
See Appendix for important disclosures regarding Reserves
24
Condensate Pricing
Strong demand and premium price for the long term
Western Canadian Condensate Pricing
• 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
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 still does
June 2016
25
Lower Montney Activity
NuVista Data Collection In Progress
R5W6
R7W6
R9W6
T70
R3W6
Pipestone
NVA 15-13-68-7W6 Vertical
Over-pressured – 133 Bbls/MMcf condy
Elmworth
• NuVista has good distribution of
vertical wells and cores
T68
Wapiti
Gold Creek
• NuVista vertical completion: over
pressured, condensate-rich
SCL 1-33-67-5W6
Producing
ACL 1-7-67-7W6
Producing
Confidential: 07-Oct-2015
T66
Karr
SCL 9-27-66-7W6
Confidential: 14-Feb-2016
7Gen 13-24-65-5W6
Producing (dual lateral)
South Wapiti
NVA Lands
• Multiple pilot wells in progress by
industry – Early Production Data
Emerging
Bilbo
• NuVista pilot deferred until
commodity price recovery
7Gen 12-32-64-5W6
Producing
Montney Wells
LWR Montney A Wells
LWR Montney Cores
June 2016
Kakwa
7Gen 15-22-63-3W6
Producing
Confidential 30-Jan-2016
26