CORPORATE PRESENTATION August 2016

CORPORATE PRESENTATION
August 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.
August 2016
1
NuVista Snapshot
NuVista Corporate Info (June 30, 2016)
TSX Trading Symbol:
Market Capitalization:
Basic Shares Outstanding:
Bank Revolver Capacity:
Percent Drawn:
Net Debt:Cashflow1:
GRANDE PRAIRIE
NVA
~$1.0 billion
156.8 million
$200 million
45%
1.1x
2016 Guidance
Production:
Capital Investment:
WAPITI
24,500 – 25,500 Boe/d
$165 – $175 million
Funds from Operations2:
$120 – $130 million
Production (MBoe/d)
EDMONTON
30
25
20
17%
15
CALGARY
10
5
0
Operating areas
25%
28%
27%
2013*
1
June 2016 net debt to Q216 Annualized Funds from Operations
August 2016
2 2H/16
75%
~90%
95+%
50%
2014
Wapiti Montney
Pricing Assumptions: $2.56/GJ AECO and US$46/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
Moderating short term pace of
spend 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 $1.75/Boe for 2016
Efficiency and Flexibility
August 2016
(1)Range
refers to Strip and Upside pricing cases, refer to Slide 7 for detailed assumptions
3
The Alberta Condensate-Rich Montney
… A Sweet Spot in a "World Class" Play
1. Scalable/Repeatable
• Deposition on the shelf edge – not
isolated pockets
• Gas charged top to bottom
• Over-pressured – low water saturation
High
Quality
Reservoir
2. Porous and Permeable
• Hydrocarbon filled porosity up to 9%
(typically 4-5%)
• Sand/silt reservoir exhibits much better
permeability
Overpressured
150-200m Thick
3. Condensate-rich
• High liquids and condensate
demonstrated in all our wells to date
4. Thick Formation
Condensate
Rich
• 150 – 200 metres
• Multiple developable layers of resource
August 2016
4
The Alberta Condensate-Rich Montney
Industry Drilling and Production Growth Continues
Elmworth to Kakwa Montney HZ Activity Update*
• High level of industry activity continues
T70
• > 850 Montney HZ wells licensed and/or drilled
to date
T69
T68
• Montney gas production exceeding 0.8 Bcf/d
T67
Elmworth to Kakwa Production Growth*
900
Avg. Gas Rate
Producing Well Count
500
800
400
700
350
600
300
500
250
400
200
300
150
200
100
100
50
0
August 2016
T65
450
0
Producing Hz Well Count
Avg. Calendar Day Gas (MMcf/d)
1000
T66
T64
NuVista
Encana
Paramount
Sinopec-Daylight
CNRL
Seven Generations
Shell
Apache
Montney Licenses
and Hz Wells
R10R9
W6W6
T63
T62
T61
R8W6
R6W6
R4W6
*Excludes southern areas of Alberta Condensate-rich Montney (Resthaven and Simonette). Map is an estimate of Industry land positions compiled from public data
R2W6
5
2016 Capital Guidance
Ability to Adapt to Commodity Price Environment
2015A FY Capex
($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-$160M
•
10-11 Wells in Bilbo & Elmworth
•
Minimal infrastructure spend
August 2016
2016FY Capex – June Forecast
($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
$140
Upside Case
3.0
24.5
26.0
2016E
2017E
2016E
2017E
20
15
22.4
10
2015A
2017E
Debt ($MM)(1)(3)
Cashflow(1) ($MM)
$200
22.4
25.5
1.0
Strip Case
Term Debt
$175
Bank Debt
$250
$150
$100
$125
$125
$130
$10
$120
$50
$150
$125
$50
$50
2015A
(1)Assumptions:
2016E
2017E
2016 STRIP & UPSIDE: US$43/bbl WTI; C$2.10/GJ AECO; 1.32:1.0 C$: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
August 2016
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
$12
0
$10
1,000
Depth (m)
($MM)
$6
$4
2015
2016
Record Wells
3,000
4,000
Recent
RecentRecord
wells:
Wells:
4,700m
in 17 days;
4,700m
5,500m in
in 16
21 days;
days
6,400m in 27 days
5,000
$2
6,000
$0
7,000
2013
2014
2015
0
2016E
Montney Drilling & Completion Cost per Stage
Cost per Stage
$500
25
$400
20
$300
15
$200
10
$100
5
$0
0
2013
August 2016
2014
2015
2016E
10
15
20
Days
25
30
35
40
• Drilling and completion costs coming down steadily
from efficiency improvements
30
No. of Stages
5
Operational Highlights
Number of Stages
($000)
2014
2,000
$8
$600
2013
• Record drilling cost of $2.8 MM with ~4,700 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
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
Sales Prod (Boe/d)
2015 Type Curve (4.4 bcf, 75 bbl/mmcf)
2011-2013 (11 Wells)
2014 (12 Wells)
2015+ (13 Wells)
600
Cumulative Production (MBoe)
Cumulative Production (MBoe)
400
Bilbo Well Production-to-Date
400
300
200
1,200
900
100
600
300
0
0
0
0
August 2016
6
12
Time (Months)
18
6
24
NuVista's type curve based on Management's best estimates; Type Curve: Bcf = EUR; Bbls/MMcf = C5+ yield
12
18
24
30
36
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 (13 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
Sales Prod (Boe/d)
1,200
900
100
600
300
0
0
0
0
August 2016
6
12
Time (Months)
18
6
24
NuVista's type curve based on Management's best estimates; Type Curve: Bcf = EUR; Bbls/MMcf = C5+ yield
12
18
24
30
36
Time (months)
10
Montney Operations
Activity Update
R8W6
Activity Highlights
• 3 New Bilbo IP30's in Q2
R7W6
T70
R6W6
Elmworth
16 Wells Producing in the Development Block (IP30)
4 Elmworth Extension wells Producing (IP30)
Three-Well Pad on-stream in September
Two-well Pad drilling
• Currently Drilling with 2 rigs
• >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
Gold Creek
T68
NEW ERH IP30:
T67
Bilbo
T66
Attractive Land Tenure
•
NuVista has over 135,000 gross acres of land
(210 sections @ 86% WI)
6 Producers (IP30)
8.0 MMcf/d
1,222 Bbl/d
2,268 Boe/d
153 Bbl/MMcf
36 Producers (IP30)
2 New Development IP30's
1 New Extended-reach well IP30
Two-well pad drilling
NVA New IP30
NVA Producing Montney (IP30)
•
Minimal 3rd party encumbrances
NVA In-Progress Wells
•
Manageable expiries
Montney HZ’s
August 2016
Raw Gas:
Condensate:
Total Sales:
CGR:
11
Elmworth Development Block
Volume Ramp In-Progress
R9W6
10
Cumulative-to-Date
9
Production (Mboe/d)
T69
North Montney Sales Production
1 R8W6
Rig Drilling
3 Well pad on-stream in September
Sales Gas
Bbls/MMcf
8
Condensate
7
Butane
6
Propane
NGL's
C5+
9
9
39
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
August 2016
IP30
IP60
IP90
IP180
IP360
Raw Gas
(Mcf/d)
C5+
(Bbl/d)
Total
Sales
(Boe/d)
C5+ Yield
(Bbl/
MMcf)
Well
Count
6,297
309
1,298
49
16
5,558
263
1,154
47
16
5,234
242
1,078
46
15
4,322
176
837
41
13
3,186
126
635
39
8
12
Bilbo Development Block
Focus on Efficient Production Additions in 2016
South Montney Sales Production
3 New IP30's
Two-well Pad Drilling
16
T66
14
Extended Reach HZ IP30:
Raw Gas:
Condensate:
Total Sales:
CGR:
8.0 MMcf/d
1,222 Bbl/d
2,268 Boe/d
153 Bbl/MMcf
Production (Mboe/d)
12
10
Cumulative-to-Date
Bbls/MMcf
5
Sales Gas
Condensate
4
NGL's
C5+
Butane
Propane
76
8
6
4
2
0
T65
Bilbo Well Performance
NVA Montney IP30 Wells
NVA Montney In-Progress Wells
R6W6
August 2016
IP30
Raw Gas
(Mcf/d)
C5+
(Bbl/d)
Total
Sales
(Boe/d)
C5+
Yield
(Bbl/
MMcf)
Well
Count
6,312
672
1,638
106
35
Montney Horizontal Wells
IP60
5,610
526
1,393
94
33
NVA 3-36 Compressor and connect
to Keyera
IP90
5,135
453
1,249
88
32
IP180
4,379
357
1,039
82
28
IP360
3,319
236
758
71
23
13
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
August 2016
14
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
10,000
40
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
35 MMcf/d
5,000
20
0
2013
SemCAMS
August 2016
2014
Keyera
2015
2016
Min TOP Commitment
17 MMcf/d
2017
0
* Contracts term are ~10 years from start date
15
Commodity Price Risk Management
We are well hedged with under 10% AECO exposure for 2016
Crude Oil Hedge Position
70.00
2,500
60.00
50.00
2,000
40.00
1,500
30.00
1,000
20.00
500
Price, C$/Bbl
3,000
Floor C$ WTI price of
$75.92/Bbl on ~45% of
2016 Q3-Q4 net
production
10.00
2016 Q3
Bbl/d Capped
2016 Q4
2017 Q1
Bbl/d Uncapped
2017 Q2
Avg. Floor
Avg. Ceiling
Natural Gas Hedge Position
120,000
Hedged Volume, GJ/d
80.00
4.50
100,000
3.75
80,000
3.00
60,000
2.25
40,000
1.50
20,000
0.75
Price, C$/GJ
Hedged Volume, Bbl/d
3,500
Floor AECO price of
$3.47/Mcf on ~68% of
2016 Q3-Q4 net
production
Only 5% of gas volumes
exposed to AECO this
summer
2016 Q3 2016 Q4 2017 Q1 2017 Q2 2017 Q3 2017 Q4 2018 Q1 2018 Q2 2018 Q3 2018 Q4 2019 Q1
GJ/d Capped
August 2016
GJ/d Uncapped
GJ/d AECO-NYMEX Basis
Avg. Floor
Basis includes some Chicago pricing. Includes NYMEX hedges converted to an AECO equivalent price.
Avg. Ceiling
16
NuVista Operating Results
2016 Guidance
Corporate Production (Boe/d)
30,000
25,000
Wapiti Montney
23,215
2016 Actual Production
(Boe/d)
2016 Prod. Guidance
(Boe/d)
Q1
25,484
24,500 - 25,000
Q2
23,451
Not disclosed
2016 FY
-
24,500 - 25,500
2016 Actual Funds
from Operations
($MM)
2016 Funds from
Operations Guidance
($MM) (1)
Q1
$30.3
Not disclosed
Q2
$35.6
Not disclosed
2016 FY
-
$120 - $130
2016 Actual Capex
($MM)
2016 Capex Guidance
($MM)
Q1
$61.2
Not disclosed
Q2
$28.8
Not disclosed
2016 FY
-
$165 - $175
Other Properties
21,448
21,622
23,355
25,484
23,451
20,000
15,000
10,000
72%
72%
76%
79%
81%
83%
5,000
Q115
Q215
Q315
Q415
Q116
Q216
Funds from Operations
Funds from Operations ($MM)
$45
$40
($MM)
$35
$30
$14.52
$15.53
$16.00
Funds from Operations ($/BOE)
$15.15
$16.69
$13.06
$25
$20
$15
$25
$10
$20
($/BOE)
$50
$15
$5
$10
$5
$0
$0
Q115
August 2016
Q215
Q315
Q415
Q116
Funds from Operations and netbacks strong despite low
commodity prices
Q216
(1) Based on commodity pricing of US$50/Bbl WTI and $2.10/GJ AECO
17
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
August 2016
18
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.
August 2016
19
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.
August 2016
20
APPENDIX
August 2016
21
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
4.7
377
263
462
489
256
666
Total Sales C5+ Yield
(Boe/d)
(Bbl/MMcf)
1,307
543
876
1,635
1,044
1,316
56
146
161
67
55
142
8-12 On-production
16-1 On-production
16-19 On-production
Cumulative Production to Date (August 6, 2016)
Well
Cumulative
Total
Days on C5+ Yield Condensate Sales Gas
Prod
(Bbl/MMcf) (Mbbls)
(MMcf)
(MBoe)
16-19
395
55
57
860
217
13-25
232
123
36
257
81
1-28
497
120
127
921
287
16-01
280
52
45
731
182
16-27
372
39
43
928
213
8-12
100
106
42
304
100
August 2016
16-27 On-production
1-28 On-production
22
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
August 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
23
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
August 2016
24
Lower Montney Activity
NuVista Data Collection In-Progress
R9W6
T70
R5W6
R7W6
Pipestone
R3W6
SCL 15-1-69-6W6
Tested: 1.9 MMcf/d and 174 bpd C5+
Elmworth
NVA 15-13-68-7W6 Vertical
Over-pressured – 133 Bbls/MMcf condy
T68
Wapiti
ACL 1-7-67-7W6
CTD: 0.9 bcf, Test CGR: 54
Gold Creek
• NuVista has good distribution of
vertical wells and cores
• NuVista vertical completion: over
pressured, condensate-rich
SCL 1-33-67-5W6
CTD: 0.1 bcf, Current CGR: 100
Karr
T66
7Gen 13-24-65-5W6
CTD: 0.2 bcf, 43 mbbl C5+ (SI)
SCL 02/9-27-66-7W6
CTD: 0.5 bcf, IP30 CGR: 85
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
CTD: 0.3 bcf, Current CGR: 254
Montney Wells
LWR Montney A Wells
LWR Montney Cores
August 2016
Kakwa
7Gen 02/9-22-63-3W6
RR: Feb 2015 (standing)
25